e10vk

10-K 1 f04196e10vk.htm FORM 10-K e10vk

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

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	6001 Bollinger Canyon Road, San Ramon, California 94583

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

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

NONE

(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 Preferred stock purchase rights		New York Stock Exchange, Inc. 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 x 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. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). x

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 — $99,547,278,421 (As of June 30, 2004)

Number of Shares of Common Stock outstanding as of February 25, 2005 — 2,104,440,278

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2005 Annual Meeting and 2005 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2005 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		6
		Net Production of Crude Oil and Natural Gas Liquids and Natural Gas		7
		Acreage		8
		Reserves		9
		Contract Obligations		9
		Development Activities		10
		Exploration Activities		10
		Review of Ongoing Exploration and Production Activities in Key Areas		11
		Petroleum — Sale of Natural Gas and Natural Gas Liquids		21
		Petroleum — Refining Operations		22
		Petroleum — Sale of Refined Products		23
		Petroleum — Transportation		24
		Chemicals		25
		Coal		26
		Synthetic Crude Oil		26
		Global Power Generation		26
		Gas-to-Liquids		26
		Research and Technology		26
		Environmental Protection		27
		Website Access to SEC Reports		27
	2.	Properties		28
	3.	Legal Proceedings		28
	4.	Submission of Matters to a Vote of Security Holders		28
		Executive Officers of the Registrant at March 1, 2005		29

PART II
	5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchaser of Equity Securities		31
	6.	Selected Financial Data		31
	7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
	7A.	Quantitative and Qualitative Disclosures About Market Risk		31
	8.	Financial Statements and Supplementary Data		32
	9.	Changes in and Disagreements with Auditors on Accounting and Financial Disclosure		32
	9A.	Controls and Procedures		32
		(a) Evaluation of Disclosure Controls and Procedures		32
		(b) Management’s Report on Internal Control Over Financial Reporting		32
		(c) Changes in Internal Control Over Financial Reporting		32
	9B.	Other Information		32

PART III
	10.	Directors and Executive Officers of the Registrant		33
	11.	Executive Compensation		33
	12.	Security Ownership of Certain Beneficial Owners and Management		33
	13.	Certain Relationships and Related Transactions		33
	14.	Principal Accounting Fees and Services		34

PART IV
	15.	Exhibits, Financial Statement Schedules		34
		Schedule II — Valuation and Qualifying Accounts		35
		Signatures		36
EXHIBIT 12.1
EXHIBIT 21.1
EXHIBIT 23.1
EXHIBIT 24.1
EXHIBIT 24.2
EXHIBIT 24.3
EXHIBIT 24.4
EXHIBIT 24.5
EXHIBIT 24.6
EXHIBIT 24.7
EXHIBIT 24.8
EXHIBIT 24.9
EXHIBIT 24.10
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2
EXHIBIT 99.1
EXHIBIT 99.2

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,” “schedules,” “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. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, 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; 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 crude oil and natural 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 war, accidents, political events, civil unrest or severe weather; potential liability for remedial actions under existing or future environmental laws or regulations; 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; the company’s acquisition or disposition of assets; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and those set forth under the heading “Risk Factors” in Part I, Item 1 of this Annual Report. 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 Corporation,¹ 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 conducts business activities 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 pipeline, marine vessel, motor equipment and rail car. Chemicals operations include the manufacture and marketing, by affiliates, of commodity petrochemicals 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 and E-5 of this Annual Report on Form 10-K. As of December 31, 2004, ChevronTexaco had more than 56,000 employees (including about 9,300 service station employees). Approximately 25,000, or 45 percent, of the company’s employees were employed in U.S. operations.

Overview of Petroleum Industry

Petroleum industry operations and profitability are influenced by many factors, and individual petroleum companies have little control over some of them. Governmental policies, particularly in the areas of taxation, energy and the environment have a significant impact on petroleum activities, regulating 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. Variations in the components of refined products sales due to seasonality are not primary drivers of changes in the company’s overall annual earnings.

Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. ChevronTexaco competes with fully integrated major petroleum companies, as well as independent and national petroleum companies for the acquisition of crude oil and natural gas leases and other properties, and for the equipment and labor required to develop and operate those properties. In its downstream business, 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 through FS-21 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.

¹ Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. 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 stated otherwise, it 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.

Risk Factors

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


	*ChevronTexaco is exposed to the effects of changing commodity prices.*

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


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

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


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

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


	*ChevronTexaco’s business subjects the company to liability risks.*

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


	*Political instability could harm ChevronTexaco’s business.*

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

In certain locations, 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, acts of violence 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. At December 31, 2004, approximately 27 percent of the company’s proved reserves were located in Kazakhstan. The company also has significant interests in Organization of Petroleum Exporting Countries (OPEC)-member countries

including Indonesia, Nigeria and Venezuela. Approximately 25 percent of the company’s net proved reserves, including affiliates, were located in OPEC countries at December 31, 2004.

ChevronTexaco Strategic Direction

ChevronTexaco’s primary objective is to achieve sustained financial returns from its operations that will enable it to outperform its competitors. The company set a goal to generate the highest total stockholder return (based on a combination of stock price appreciation and reinvested dividends) among a designated peer group for the five-year period 2000-2004. BP, ExxonMobil and Royal Dutch Shell – among the world’s largest publicly traded integrated petroleum companies – comprised the company’s designated competitor peer group for this purpose. For the five years ending December 31, 2004, ChevronTexaco tied one other company in the peer group for the highest total stockholder return.

As a foundation for attaining this goal, the company had established four key priorities, which continue into 2005:


	•	*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).

	•	*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 primary areas described above.

The company’s long-term strategies for its largest businesses build on this framework and focus on balancing financial returns and growth. The strategies for upstream (exploration and production) are to grow profitability in core areas, build new legacy positions, and commercialize the company’s natural gas equity resource base by targeting North American and Asian markets. The primary strategy for downstream (refining, marketing and transportation) is to continue to improve returns by focusing on areas of market and supply strength.


(b)	Description of Business and Properties

The upstream and downstream activities of the company are widely dispersed geographically. The company has operations in North America, South America, Europe, Africa, Middle East, Central and Far East Asia, and Australia. Besides the large upstream and downstream businesses, the company’s other comparatively smaller business segment is chemicals, which is conducted by the company’s 50 percent-owned affiliate – Chevron Phillips Chemical Company LLC (CPChem) – and the wholly owned Chevron Oronite Company (Chevron Oronite). CPChem has operations in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar, Mexico and Belgium. Chevron Oronite is a fuel and lubricating-oil additives business that owns and operates facilities in the United States, France, the Netherlands, Singapore and Japan and has equity interests in facilities in India and Mexico.

ChevronTexaco also owns an approximate 25 percent equity interest in the common stock of Dynegy Inc. (Dynegy), an energy provider engaged in power generation, gathering and processing of natural gas, and the fractionation, storage, transportation and marketing of natural gas liquids. The company holds an additional investment in Dynegy preferred stock. Refer to page FS-11 and Note 8 on page FS-36 for further information relating to the company’s investment in Dynegy.

Tabulations of segment sales and other operating revenues, earnings, income taxes for the three years ending December 31, 2004, and assets as of the end of each year — for the United States and the company’s major international geographic areas — may be found in Note 9 to the consolidated financial statements beginning on page FS-36 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 14 and 15 on pages FS-39 to FS-41.

Capital and Exploratory Expenditures

A discussion of the company’s capital and exploratory expenditures is contained on pages FS-12 and FS-13 of this Annual Report on Form 10-K.

Petroleum — Exploration and Production

The following table summarizes the company’s and affiliates’ net production of liquids and natural gas production for 2004 and 2003.

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


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

		2004		2003		2004		2003		2004		2003

United States:
	California		221		231		108		112		239		250
	Gulf of Mexico		154		189		815		1,059		290		365
	Texas		62		84		382		463		125		161
	Wyoming		10		10		166		179		38		40
	Other States		58		48		402		415		125		117

Total United States			505		562		1,873		2,228		817		933

Africa:
	Angola		140		154		26		—		144		154
	Chad		37		8		—		—		37		8
	Nigeria		119		123		59		50		129		131
	Republic of Congo		12		13		—		—		12		13
	Democratic Republic of the Congo³		4		9		—		—		4		9
Asia-Pacific:
	Partitioned Neutral Zone (PNZ)⁴		117		134		20		15		120		136
	Australia		43		48		305		284		93		95
	China		18		23		—		—		18		23
	Kazakhstan		31		25		125		101		52		42
	Thailand		20		25		93		104		35		42
	Philippines		7		8		131		140		28		31
	Papua New Guinea⁵		—		4		—		—		—		4
Indonesia			215		223		149		166		240		251
Other International:
	United Kingdom		106		116		340		378		163		179
	Canada		62		73		51		110		71		91
	Argentina		45		52		64		74		56		65
	Denmark		46		42		130		99		68		59
	Norway		11		10		2		—		11		10
	Venezuela		5		5		34		21		11		9
	Colombia		—		—		210		206		35		35
	Trinidad and Tobago		—		—		135		116		23		19

Total International			1,038		1,095		1,874		1,864		1,350		1,406

Total Consolidated Operations			1,543		1,657		3,747		4,092		2,167		2,339
	Equity Affiliates⁶		167		151		211		200		202		184

Total Including Affiliates ^7,8			1,710		1,808		3,958		4,292		2,369		2,523


	1	Net production excludes royalty interests owned by others.
	2	Barrels of oil-equivalent (BOE) is crude oil and natural gas liquids plus natural gas converted to oil-equivalent gas (OEG) barrels at 6 MCF = 1 OEG barrel.
	3	The company sold its interest in the Democratic Republic of the Congo in mid-2004.
	4	Located between the Kingdom of Saudi Arabia and the State of Kuwait.
	5	The company sold its interest in Papua New Guinea and resigned operatorship of the Kutubu, Gobe and Moran oil fields in 2003.
	6	Affiliates include Tengizchevroil (TCO) in Kazakhstan and Hamaca in Venezuela.
	7	Includes natural gas consumed on lease of 343 and 333 million cubic feet per day in 2004 and 2003, respectively.
	8	Does not include other produced volumes:


Athabasca Oil Sands – net	27	15	—	—	27	15
Boscan Operating Service Agreement	113	99	—	—	113	99

In 2004, ChevronTexaco conducted its exploration and production operations in the United States and approximately 25 other countries. Worldwide oil-equivalent production in 2004, including volumes produced from oil sands and production under an operating service agreement, declined approximately 5 percent from 2003. The decline was largely the result of lower production in the United States due to normal field declines, property sales and curtailments as a result of damages to producing operations from hurricanes in the Gulf of Mexico in September 2004. International oil-equivalent production was down marginally between years. Refer to the “Results of Operations” section beginning on page FS-6 for a detailed discussion of the factors explaining the 2002-2004 changes in production for crude oil and natural gas liquids and natural gas.

For the past six years, the company’s worldwide oil-equivalent production, including the volumes produced from oil sands and production under an operating service agreement, has followed a downward trend. Production in 2004 was 85 percent of 1998 levels, equivalent to an average annual decline rate of about 3 percent. For 2005, the company again expects worldwide oil-equivalent production to be lower. Increases internationally in 2005 are not expected to fully offset lower rates in the United States, which the company projects will result largely from normal field declines and the absence of production associated with property sales. The actual level of worldwide production in 2005 remains uncertain for reasons including the potential for constraints imposed by OPEC, and disruptions caused by weather, local civil unrest and other factors. Production capacity in the 2006-2008 period may permit the worldwide oil-equivalent production level to increase from that expected in 2005. Refer to the “Review of Ongoing Exploration and Production Activities in Key Areas” beginning on page 11 for a discussion of the company’s major oil and gas development projects.

Acreage

At December 31, 2004, the company owned or had under lease or similar agreements undeveloped and developed oil and gas properties located throughout the world. The geographical distribution of the company’s acreage is shown in the following table.

Acreage¹ at December 31, 2004

(Thousands of Acres)


										Developed
										and
		Undeveloped²				Developed²				Undeveloped

		Gross		Net		Gross		Net		Gross		Net

United States:
	California		112		91		189		171		301		262
	Gulf of Mexico		3,782		2,780		1,898		1,325		5,680		4,105
	Other U.S.		3,236		2,628		4,118		2,201		7,354		4,829

Total United States			7,130		5,499		6,205		3,697		13,335		9,196

Africa			19,836		7,103		852		252		20,688		7,355
Asia-Pacific			22,369		11,511		1,959		632		24,328		12,143
Indonesia			5,396		3,267		279		267		5,675		3,534
Other International			34,207		18,490		3,046		1,758		37,253		20,248

Total International			81,808		40,371		6,136		2,909		87,944		43,280

Total Consolidated Companies			88,938		45,870		12,341		6,606		101,279		52,476
Equity Affiliates			1,022		485		129		58		1,151		543

Total Including Affiliates			89,960		46,355		12,470		6,664		102,430		53,019


	1	Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage is the sum of the company’s fractional interests in gross acreage.
	2	Developed acreage is spaced or assignable to productive wells. Undeveloped acreage is acreage where wells have not been drilled or completed to permit commercial production and that may contain undeveloped proved reserves. The gross undeveloped acres that will expire in 2005, 2006 and 2007 if production is not established are 10,573, 7,062 and 3,374, respectively.

Refer to Table IV on page FS-62 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 2004, 2003 and 2002. The following table summarizes gross and net productive wells at year-end 2004 for the company and its affiliates.

Productive Oil and Gas Wells at December 31, 2004


		Productive¹				Productive¹
		Oil Wells				Gas Wells

		Gross²		Net²		Gross²		Net²

United States:
	California		22,892		21,363		178		54
	Gulf of Mexico		1,895		1,609		1,060		841
	Other U.S.		19,772		6,298		10,029		4,838

Total United States			44,559		29,270		11,267		5,733

Africa			1,707		601		7		3
Asia-Pacific			1,985		960		213		88
Indonesia			7,035		6,980		81		69
Other International			1,426		906		233		97

Total International			12,153		9,447		534		257

Total Consolidated Companies			56,712		38,717		11,801		5,990
Equity Affiliates			370		123		—		—

Total Including Affiliates			57,082		38,840		11,801		5,990

Multiple completion wells included above:			924		615		552		413


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

Reserves

Table V, beginning on page FS-63, sets forth the company’s proved net oil and gas reserves, by geographic area, as of December 31, 2004, 2003 and 2002. Also, refer to Table V for a discussion of major changes to proved reserves by geographic area for 2004. During 2004, the company provided oil and gas reserves estimates for 2003 to the Department of Energy, Energy Information Agency. Such estimates are consistent with and do not differ more than 5 percent from the information furnished to the SEC in this Annual Report on Form 10-K. During 2005, the company will file estimates of oil and gas reserves with the Department of Energy, Energy Information Agency, consistent with the reserve data reported in Table V.

Contract Obligations

The company sells crude oil, natural gas and natural gas liquids 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.

In the United States, the company is contractually committed to deliver to third parties and affiliates approximately 180 billion cubic feet of natural gas through 2007 from United States reserves. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed U.S. reserves. These contracts include variable-pricing terms.

Outside the United States, the company is contractually committed to deliver to third parties approximately 700 billion cubic feet of natural gas through 2007 from Australian, Canadian, Colombian and Philippine reserves. The sales contracts contain variable pricing formulas that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery and that in some cases consider inflation or other factors.

The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed Australian, Colombian and Philippine reserves. The company plans to meet its Canadian contractual delivery commitments through third-party purchases.

Development Activities

Details of the company’s development expenditures and costs of proved property acquisitions for 2004, 2003 and 2002 are presented in Table I on page FS-58.

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, 2004. A “development well” is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. “Wells drilling” includes wells temporarily suspended.

Development Well Activity


						Net Wells Completed¹
		Wells
		Drilling at
		12/31/04				2004				2003				2002

		Gross²		Net²		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States
	California		–		–		636		1		418		–		227		1
	Gulf of Mexico		2		1		43		3		47		6		78		4
	Other U.S.		18		8		221		3		232		12		333		11

Total United States			20		9		900		7		697		18		638		16

Africa			6		2		36		–		24		–		27		–
Asia-Pacific			46		8		84		–		43		–		44		–
Indonesia			–		–		163		–		562		–		426		–
Other International			7		1		84		–		107		–		140		–

Total International			59		11		367		–		736		–		637		–

Total Consolidated Companies			79		20		1,267		7		1,433		18		1,275		16
Equity Affiliates			4		2		20		–		18		–		20		–

Total Including Affiliates			83		22		1,287		7		1,451		18		1,295		16


	1	Indicates the fractional number of wells completed during the year regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency.
	2	Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned and the sum of the company’s fractional interests in gross wells.

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, 2004. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unproved areas and include delineation wells, which are wells drilled to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend a known reservoir beyond the proved area.

“Wells drilling” includes wells temporarily suspended. Refer to the suspended wells discussion in “Litigation and Other Contingencies” in Management’s Discussion and Analysis of Financial Condition and Results of Operations on page FS-17 and Note 1, Summary of Significant Accounting Policies; “Properties, Plant and Equipment” on pages FS-30 and FS-31 and Note 21, Accounting for Suspended Exploratory Well Costs beginning on page FS-45 for further discussion.

The ultimate disposition of these well costs is dependent on one or more of the following: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory drilling that is under way or firmly planned, and (3) securing final regulatory approvals for development.

Exploratory Well Activity


						Net Wells Completed¹
		Wells
		Drilling
		at 12/31/04				2004				2003				2002

		Gross²		Net²		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States:
	California		–		–		–		–		–		–		–		–
	Gulf of Mexico		19		10		13		8		25		9		44		10
	Other U.S.		–		–		3		1		2		1		13		12

Total United States			19		10		16		9		27		10		57		22

Africa			–		–		3		1		3		1		6		1
Asia-Pacific			1		1		16		–		6		3		4		–
Indonesia			–		–		2		–		1		–		–		1
Other International			5		3		3		7		2		4		7		9

Total International			6		4		24		8		12		8		17		11

Total Consolidated Companies			25		14		40		17		39		18		74		33
Equity Affiliates			–		–		–		–		–		–		4		–

Total Including Affiliates			25		14		40		17		39		18		78		33


	¹	Indicates the fractional number of wells completed during the year regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency.

	²	Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned and the sum of the company’s fractional interests in gross wells.

Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2004, 2003 and 2002 are presented in Table I on page FS-58.

Review of Ongoing Exploration and Production Activities in Key Areas

ChevronTexaco’s 2004 key upstream activities, also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations beginning on page FS-2, are presented below. The comments 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.

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

Consolidated Operations


a)	United States

The United States upstream activities are concentrated in the Gulf of Mexico, California, Louisiana, Texas, New Mexico and the Rocky Mountains. Average daily net production during 2004 was approximately 505,000 barrels of liquids and 1.9 billion cubic feet of natural gas, or 817,000 barrels per day on an oil-equivalent basis. The company announced plans in 2003 to sell interests in nonstrategic producing properties in the United States, and during 2004 substantially all of the larger asset packages were sold. The effect of these sales on 2004 net oil-equivalent production was about 30,000 barrels per day. The remaining properties earmarked for sale are expected to be disposed of during 2005 and represent less than 1 percent of the U.S. oil-equivalent production at the end of 2004. Refer to Table V beginning on page FS-63 for a discussion of the reserves and different characteristics for the major U.S. producing areas.


		California: The company has significant production in the San Joaquin Valley. In 2004, average daily net production was 217,000 barrels of crude oil, 108 million cubic feet of natural gas and 4,000 barrels of natural gas liquids, or 239,000 barrels of daily net production on an oil-equivalent basis. Approximately 84 percent of the crude oil production is considered heavy oil (typically with API gravity lower than 22 degrees).


		Gulf of Mexico: Combining the company’s interest in the shelf and deepwater areas and on-shore Louisiana, average daily net production rates during 2004 were 138,000 barrels of crude oil, 815 million cubic feet of natural gas and 16,000 barrels of natural gas liquids, or approximately 290,000 oil-equivalent barrels daily. In deepwater, the company has an interest in three significant producing fields: Genesis, Petronius and Typhoon. Petronius, 50 percent-owned and operated, maintained a daily net production of 14,000 barrels of crude oil and 25 million cubic feet of natural gas in 2004.

The 57 percent-owned and operated Genesis averaged daily net production of approximately 13,000 barrels of crude oil and 18 million cubic feet of natural gas in 2004. Petronius production was shut-in for repairs following hurricane damage in September 2004, and is expected to resume producing in March 2005. Typhoon, which is 50 percent-owned and operated, had average daily net production of approximately 11,000 barrels of crude oil and natural gas liquids and 14 million cubic feet of natural gas in 2004, including production from the Boris Field that utilizes the Typhoon production facility.

Development continues on the company-operated Perseus and Tahiti projects, which are not yet on production. The company’s ownership interests are 50 percent and 58 percent, respectively. At Perseus, platform rig damage due to the September 2004 hurricane delayed the estimated completion of the first producing well until April 2005. A second production well is scheduled to follow in the first quarter 2006. Average net production in 2005 from the first Perseus well through the Petronius facilities is estimated at more than 4,000 net barrels of oil-equivalent per day after start-up. The initial booking of proved undeveloped reserves occurred in 2003 and a reclassification of certain reserves to proved developed will occur in early 2005, prior to the start of production from the first well. The Perseus project has an estimated production life of between six and nine years. At Tahiti, engineering and equipment procurement was in process during 2004. A successful well test of the original discovery well was also conducted in 2004. Initial booking of proved undeveloped reserves occurred in 2003, and transfer of certain reserves into the proved developed category is anticipated in 2008, when first production is scheduled to begin. Tahiti is expected to have a production life of 25 years.

In Gulf of Mexico exploration, the company participated in 11 deepwater exploratory wells during 2004 and announced two discoveries — the 50 percent-owned and operated Jack prospect and the 17 percent-owned and nonoperated Tobago prospect. Further evaluation of commercial potential also continued on the 2003 discovery at the 30 percent-owned and nonoperated Tubular Bells prospect with additional follow-up drilling planned for the 2005-to-2006 timeframe. Commercial appraisal work also continues at the nonoperated 33 percent-owned Great White Field, including an additional well that is planned in 2005, and at the nonoperated 13 percent-owned Saint Malo discovery. Proved reserves have not been recognized for these projects. Appraisal drilling also occurred in 2004 at the 63 percent-owned and operated Blind Faith. Initial production is expected by early 2008. No proved reserves have been recognized for this project. The 75 percent-owned and operated Tonga prospect was drilled in 2003 and the data from this well is under evaluation.

In December 2004, the company announced it had finalized a 20-year agreement for regasification capacity at the proposed Sabine Pass liquefied natural gas (LNG) terminal. In November 2004, the company announced it had plans to submit federal and state permit applications for a regasification terminal to import LNG located at its Pascagoula Refinery.

Other U.S. Areas: Outside of California and the Gulf of Mexico, the company manages operations in the midcontinent United States extending from the Rockies to southern Texas. In 2004, average daily net production was 130,000 barrels of crude oil and natural gas liquids and 950 million cubic feet of natural gas.


b)	Africa


		Angola: ChevronTexaco is the largest producer of crude oil and liquefied petroleum gases in Angola. The company was the first to produce in the deepwater. Cabinda Gulf Oil Company Limited (CABGOC), a wholly owned subsidiary of ChevronTexaco, is operator of two concessions, Block 0 and Block 14, off the west coast of Angola, north of the Congo River. 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 two areas – A and B – composed of 19 fields producing 116,000 barrels per day of net liquids in 2004. Area A, comprising 13 producing fields, averaged net daily production of approximately 78,000 barrels of crude oil and 1,000 barrels of liquefied petroleum gas (LPG) in 2004. Area B, which is now the combination of areas previously known as Area B and Area C, has six producing fields and averaged daily net production of 37,000 barrels of crude oil in 2004. In 2004, the company finalized a 20-year extension of its Block 0 concession, which will expire in 2030. The Sanha condensate gas utilization and Bomboco crude oil project, located in Area B, began operations with the installation of facilities and the start of production in late 2004. Initial recognition of proved reserves was made at the end of 2002. Initial reclassification of reserves from proved undeveloped to proved developed occurred in 2004 and will continue in 2005 and 2006.

In Block 14, net production in 2004 from the Kuito Field, Angola’s first deepwater producing area, averaged approximately 18,000 net barrels of crude oil per day. The development plans for the Benguela, Belize, Lobito and Tomboco fields in Block 14 were approved in 2003. Phase 1 of the $2.2 billion project involves the installation of an integrated drilling and production platform and the development of the Benguela and Belize fields, projected for first oil in early 2006. Proved undeveloped reserves for these fields were booked in 1998. Phase 2 involves the installation of subsea systems, pipelines and wells for Lobito and Tomboco. Proved undeveloped reserves for these fields were booked in 2000. Phase 2 is under construction, with first oil planned for late 2006. After both phases are completed, maximum total daily production is estimated at more than 200,000 barrels of crude oil in 2008. Some proved developed reserves will be recognized near to the time of first oil. The concession for these fields will expire in 2027.

The Landana and Tombua fields were discovered in 1997 and 2001, respectively, and appraisal drilling was done from 1998 through 2002. Proved undeveloped reserves for Tombua and Landana were booked in 2001 and 2002, respectively. Feasibility studies were completed in 2004 for the Tombua-Landana development, which is targeted as the next major capital project for Block 14 and is currently in front-end engineering. Estimated capital expenditures for the development exceed $2 billion. Proved developed reserves will start to be recognized near the time of first production.

ChevronTexaco has two other concessions in Angola. Block 2, 20 percent-owned and operated, and Block FST, in which the company has a 16 percent nonoperated interest, had a combined net production of nearly 6,000 barrels of crude oil per day in 2004.

The Angola LNG Project is an integrated gas utilization project. ChevronTexaco and Sonangol, the state oil company of Angola, are co-leading the project in which the company has a 36 percent interest. Front-end engineering and design work is expected to start in the first half of 2005.

Chad-Cameroon: ChevronTexaco is a non-operating partner in a project to develop oil fields in southern Chad and transport crude oil by pipeline to the coast of Cameroon for export. Net daily production in 2004 was 37,000 barrels of crude oil. All three of the original fields are now on production. Proved undeveloped reserves were booked in 2000 and began to be reclassified to proved developed reserves in 2002. The production life of the field is estimated at 30 years.

ChevronTexaco has a 25 percent interest in the upstream operations and an approximate 21 percent interest in the pipeline.

Equatorial Guinea: ChevronTexaco is a 45 percent partner and operator of the L Block offshore the Republic of Equatorial Guinea. The first exploration well, Ballena-1, was completed in 2003. In the fourth quarter 2004, ChevronTexaco initiated partial farm-out activities and, if completed, plans to drill two stratigraphic prospects in Block L.

Libya: In early 2005, the company was awarded Block 177 in Libya’s first exploration license round under the Exploration and Production Sharing Agreement IV. The company was also made operator of Block 177 with 100 percent equity.


		Nigeria: ChevronTexaco’s principal subsidiary in Nigeria, Chevron Nigeria Limited (CNL), operates and holds a 40 percent interest in 11 concessions, predominantly in the onshore and near-offshore regions of the Niger Delta. CNL operates under a joint-venture arrangement with the Nigerian National Petroleum Corporation (NNPC), which owns 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. Effective November 2004, all the rights, duties, obligations, assets and liabilities of TOPCON and COCNL were merged into CNL. In 2004, daily net production from the 38 operated fields averaged 117,000 barrels of crude oil, 2,000 barrels of LPG and 59 million cubic feet of natural gas. Certain onshore operations in the western Niger Delta were suspended in March 2003 as a result of community disturbance.

Net onshore production capacity of about 45,000 barrels of oil per day has been shut-in since March 2003. The company has adopted a phased plan to restore these operations and has taken initial steps to determine the extent of damage and secure the properties. The company has begun initial production-resumption efforts in certain areas. The Abiteye Field, closest to the Escravos terminal, was returned to production in 2004. Restoration activities in the remaining fields will continue through 2006.

In May 2004, ChevronTexaco received a 100 percent contractor interest under a production-sharing contract arrangement in OPL (Oil Prospecting License)-247. This agreement further increased the company’s leading acreage position in the Nigerian deepwater trend.

The company also continued activities in the deepwater Agbami development. Significant progress was made toward achieving final governmental approvals and executing key agreements. During 2004, the company drilled four development wells. In early 2005, the Agbami Development had achieved the following major milestones: conversion of OPL-216 and OPL-217 to OML (Oil Mining Lease)-127 and OML-128, approval of the Field Development Plan, award of the floating production, storage, and offloading unit (FPSO) contract, concurrence on the Unit Agreement and project funding approval by partners. Proved undeveloped reserves were recognized for this project in 2002. Prior to the anticipated production start-up, in 2008, proved undeveloped reserves would be reclassified to proved developed reserves. The expected field life is approximately 20 years. ChevronTexaco’s share of contractor’s interest under the Agbami production-sharing contract arrangements are 80 percent in OML-127 and approximately 46 percent in OML-128.

In August 2003, the Aparo discovery on OPL-213 was extended with a delineation well on OPL-249. The Aparo/ Bonga SW fields straddle OPL-212, OPL-213 and OPL-249. ChevronTexaco signed an agreement with the operator of OPL-212 in 2004 to conduct technical studies in pursuit of a unitized joint development of the Aparo/ Bonga SW discovery. The timing of recognition of proved undeveloped reserves will depend on the completion of these studies and subsequent

unitization. Also on Block OPL-249, which contains the 2003 Nsiko discovery, two additional appraisal wells were drilled in 2004. Both wells confirmed the presence of producible crude oil over the entire structure.

OPL-222 activities continued in 2004 with the appraisal program for the greater Usan area and successful drilling of the fifth and sixth wells. Proved undeveloped reserves were recorded in 2004 for the Usan Field with development planned to enter the basic engineering phase in 2005. Initial production is estimated to occur in 2009 before which time certain proved undeveloped reserves would be reclassified to proved developed reserves. The company holds a 30 percent interest in this project.

At the Escravos Gas Project (EGP), onshore and offshore engineering, procurement and construction bids were received in 2003. Bids were reissued in 2004 following a review of the project design and scope. Start-up is expected in 2008 and includes adding a second gas plant with 395 million cubic feet of capacity, which would increase capacity to 680 million cubic feet of natural gas per day and increase LPG and condensate exports to 43,000 barrels per day. ChevronTexaco holds a 40 percent interest in this project.

The company is also pursuing a planned gas-to-liquids facility at Escravos. Lump-sum engineering, procurement and construction bids for the planned gas-to-liquids facility at Escravos were opened in May 2004. Construction is expected to begin during 2005, pending finalization of fiscal terms. The project is the first to use the technology and operational expertise of the Sasol Chevron global 50-50 joint venture. Project start-up is expected in 2008. Proved undeveloped reserves associated with EGP were recognized in 2002. These reserves will be reclassified to proved developed reserves as various stages of EGP and related projects are completed.

In November 2004, the company and its partners in the Brass LNG Project located in Nigeria’s central Niger Delta, awarded the contract for front-end engineering and design of its two-train liquefied natural gas facility. The project is expected to start up in 2010. No proved reserves have been recognized for this project.

In early 2005, the company announced plans to conduct a feasibility study on a potential LNG project at Olokola in southwest Nigeria. Future decisions to move forward with Olokola LNG will depend on the results of the feasibility study.

Nigeria - São Tomé and Príncipe Joint Development Zone (JDZ): The company was awarded JDZ Block 1 in 2004. In early 2005, the company signed a production sharing contract with the Joint Development Authority, under which ChevronTexaco will be the operator with a 51 percent interest.

Republic of Congo: ChevronTexaco has a 30 percent interest in Nkossa, Nsoko and Moho-Bilondo exploitation permits and a 29 percent interest in the Marine VII Kitina and Sounda exploitation permits, all of which are offshore Republic of Congo and adjacent to the company’s concessions in Angola. Net production from the company’s concessions in the Republic of Congo averaged 12,000 barrels of crude oil per day in 2004. Assessment of the Moho and Bilondo satellite fields progressed during 2004, with the drilling of the MOBIM 1 well. Work is in progress to determine the development plan for the field.

Southern Africa: Appraisal drilling is planned in 2005 to assess the size and commerciality of the successful Lianzi-1 well drilled in the 14K/A-IMI Unit, located between the Republic of Congo and Angola, in which the company is operator and holds an approximate 31 percent interest. Timing is uncertain regarding the recognition of proved reserves.


c)	Asia-Pacific


		Australia: ChevronTexaco has a 17 percent interest in the North West Shelf (NWS) Project offshore Western Australia. Daily net production from the project during 2004 averaged 17,000 barrels of condensate, 305 million cubic feet of natural gas, 15,000 barrels of crude oil and 4,000 barrels of liquefied petroleum gas. Approximately 70 percent of the natural gas was sold, primarily under long-term contracts, in the form of 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 completed during 2004 increased LNG capacity approximately 50 percent and encompassed the installation of a second 80-mile pipeline from the offshore natural gas fields to onshore facilities. The first LNG of Train 4 was produced in September 2004. A ninth LNG carrier, operated by Chevron Transport Corporation Ltd., was added to the NWS-controlled fleet. In December, the China Guangdong LNG sales purchase agreement became unconditional and the equity agreement with China National Offshore Oil Corporation (CNOOC) was completed.

ChevronTexaco operates the crude oil producing facilities on Barrow and Thevenard Islands, which had combined net crude oil production of 7,000 barrels per day in 2004. ChevronTexaco equity interest in this operation is 57 percent for Barrow Island and 51 percent for Thevenard Island.

ChevronTexaco is the operator of the 57 percent-owned Gorgon-area fields and has between 50 to 100 percent interest in other Greater Gorgon fields off the northwest coast of Australia. The 12 discovered natural gas fields straddle 17 lease blocks in the Greater Gorgon Area. The Gorgon Project is moving forward on front-end-engineering-and-design feasibility work, targeting initial production for 2009-2010. Preliminary gas sales agreements have been signed with CNOOC and with a planned North American West Coast terminal. Proved reserves have not been recognized for any of the Gorgon fields and reserves booking is contingent on securing LNG sales and purchase agreements and other key project milestones.

In 2004, the company drilled the successful wholly owned Wheatstone-1 natural gas well located offshore Western Australia. Production tests were completed in 2004 and the company is conducting a 3-D seismic program.

Cambodia: ChevronTexaco operates and holds a 55 percent interest in Block A, located offshore Cambodia in the Gulf of Thailand, after a 15 percent farm-out during 2004. The concession covers approximately 1.6 million acres. ChevronTexaco processed more than 600,000 acres of 3-D seismic data and drilled four exploration wells on the second exploration campaign resulting in four crude oil discoveries in 2004. The company is evaluating appraisal and additional exploration opportunities for 2005. Proved reserves have not been recognized for this project.

China: ChevronTexaco has a 33 percent interests in Blocks 16/08 and 16/09, located in the Pearl River Delta Mouth Basin. Daily net production in 2004 from the eight fields in these blocks averaged about 10,000 barrels of crude oil. The company has a 25 percent interest in QHD-32-6 in Bohai Bay, which had 2004 average net production of about 7,000 barrels of crude oil per day, and a 16 percent working interest in Bozhong 25-1 unitized development project in Block 11/19, located in Bohai Bay, which achieved initial production in August 2004. Average net production from the field was about 1,000 barrels of crude oil per day. The company has interest ranging from 64 to 100 percent interest in five prospective natural gas blocks totaling about 2.7 million acres.


		Kazakhstan: ChevronTexaco holds a 20 percent interest in the Karachaganak project. In June 2004, the company’s first Karachaganak crude oil was loaded at Russia’s Black Sea port at Novorossiysk. Phase 2 of the field development, which included construction of gas injection and liquids processing facilities and an increase in liquids export capacity via the company’s 15 percent-owned Caspian Pipeline Consortium (CPC) was completed in the third quarter 2004. Access for Karachaganak production to CPC’s pipeline allows sales of approximately 150,000 barrels per day of processed liquids (28,000 net barrels) to prices available in world markets. During 2004, Karachaganak net daily production averaged 31,000 barrels of liquids and 125 million cubic feet of natural gas. Proved developed reserves associated with Phase 2 have been added over the 2002-to-2004 timeframe. The Karachaganak operations are conducted under a 40-year concession agreement that expires in 2038.

Partitioned Neutral Zone (PNZ): Saudi Arabian Texaco Inc., a ChevronTexaco affiliate, holds a 60-year concession, originally signed in 1949, to produce onshore crude oil from the 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 interest in 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 and pays a royalty and other taxes on hydrocarbons produced. During 2004, average daily net production was 117,000 barrels of crude oil and 20 million cubic feet of natural gas.

Philippines: The company holds a 45 percent interest in the Malampaya natural gas field located about 50 miles offshore Palawan Island. Malampaya represents the first offshore production of natural gas in the Philippines. Daily net production was 131 million cubic feet of natural gas and 7,000 barrels of condensate.

Qatar: In 2004, Sasol Chevron, ChevronTexaco’s 50-50 global joint venture with Sasol of South Africa, entered into a memorandum of understanding with Qatar Petroleum to expand the Oryx gas-to-liquids project and a letter of intent to examine GTL base oils opportunities in Qatar. Qatar Petroleum and Sasol Chevron also agreed to pursue an opportunity to develop a 130,000 barrels-per-day integrated gas-to-liquids project.

Thailand: ChevronTexaco operates Blocks B8/32, 9A and G4/43 in the Gulf of Thailand. The company holds approximately a 52 percent interest in Blocks B8/32 and 9A and a 60 percent interest in Block G4/43. The company also holds a 33 percent interests in exploration Blocks 7, 8 and 9, which are currently inactive pending resolution of border issues between Thailand and Cambodia.

Block B8/32 produces crude oil and natural gas from four fields: Benchamas, Maliwan, North Jamjuree and Tantawan. Daily net production in 2004 from these fields was 93 million cubic feet of natural gas and 20,000 barrels of crude oil. During the year, 72 development wells were drilled and five wellhead platforms were installed in Block B8/32. In 2004, the company completed an upgrade of processing capacity at the Benchamas Field, increasing total capacity to approximately 65,000 barrels of crude oil per day (34,000 net barrels). Further development of the concession focused on the North and Central Benchamas Area and the development of the North Jarmjuree Field, located between the Benchamas and Tantawan fields. First production at North Jarmjuree was in the third quarter 2004.

In 2004, the company farmed-out a 25 percent interest in Block G4/43, reducing its interest to 60 percent. One exploration well and one appraisal well were drilled successfully. Environmental surveys, impact assessments for drilling and 3-D seismic survey acquisition for the first 600,000 acres were completed in 2004.


d)	Indonesia


		ChevronTexaco’s interests in Indonesia are managed by two wholly owned subsidiaries, P.T. Caltex Pacific Indonesia (CPI) and ChevronTexaco Energy Indonesia (CTEI). CPI accounts for nearly half of Indonesia’s total crude oil output and holds an interest in four production-sharing contracts. CTEI 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 interests, ChevronTexaco has a 25 percent nonoperated interest in South Natuna Sea Block B. ChevronTexaco’s share of net production during 2004 was 222,000 barrels of oil-equivalent per day in CPI-operated areas. The Duri Field in the Rokan Block, under steamflood since 1985, is the largest steamflood project in the world, with net production averaging 120,000 barrels of crude oil per day in 2004. ChevronTexaco’s net production from South Natuna Sea Block B in 2004 was about 18,000 barrels of oil-equivalent per day.


e)	Other International Areas

Argentina: ChevronTexaco operates in Argentina through its subsidiary, Chevron San Jorge S.R.L. The company and its partners hold more than 3.4 million exploration and production acres in the Neuquén and Austral basins in 19 production concessions (18 operated and one nonoperated) and seven exploration blocks (five operated and two nonoperated). Working interests range from approximately 19 percent to 100 percent in operated license areas. Farm-out agreements are under negotiations in five blocks. Net production in 2004 averaged 56,000 barrels of oil-equivalent per day.

Brazil: ChevronTexaco holds working interests ranging from 20 percent to 68 percent in five deepwater blocks totaling 1.5 million acres at year-end 2004. Exploration is concentrated in the Campos and Santos basins. In 2004, the National Petroleum Agency approved the company’s plans to evaluate the discoveries in Block BS-4 and Block BC-20, with completion expected by year-end 2006. In the Frade Field, where the company is the operator and has a 43 percent interest, the contract for front-end engineering design (FEED) for a floating, production, storage and offloading vessel and subsea systems was awarded in August 2004. Timing of initial production and booking of reserves is dependent upon FEED results which are expected in late 2005. No proved reserves have been recognized for this project.

Canada: During 2004, the company divested producing assets in western Canada and sold its wholly owned mid-stream natural gas processing business. The effect of these sales on 2004 net oil-equivalent production was about 16,000 barrels per day. The company continues to maintain strategically significant assets in Canada, including a 27 percent nonoperated interest in the Hibernia Field; a 20 percent nonoperated interest in the Athabasca Oil Sands Project, which is discussed separately on page 26; a 28 percent operated interest in the Hebron project where feasibility studies preceding the major development project are continuing; and exploration opportunities in the Mackenzie Delta and Orphan Basin. Excluding Athabasca, net daily production in 2004 from the company’s Canadian operations was 62,000 barrels of crude oil and natural gas liquids and 51 million cubic feet of natural gas.

Colombia: Until the end of 2004, ChevronTexaco operated three natural gas fields under two related contracts — the Guajira Association contract and the Build-Operate-Maintain-Transfer (BOMT) contract. The Guajira Association Contract, a 50-50 joint venture production-sharing agreement, expired in December 2004. In 2005, the company continues to operate the fields and receives 43 percent of the production for the remaining life of the fields, as well as continue to operate the BOMT contract until it expires in 2016. Net natural gas production averaged 210 million cubic feet per day in 2004.

Denmark: ChevronTexaco holds a 15 percent interest in the Danish Underground Consortium (DUC), producing crude oil and natural gas from 15 fields in the Danish North Sea and involving 12 percent to 27 percent interest in five exploration areas. The daily net production from the DUC was 46,000 barrels of crude oil and 130 million cubic feet of natural gas.

Faroe Islands: In January 2005, the company was awarded five offshore exploration blocks in the Faroe Islands second offshore licensing round. The blocks cover approximately 170,000 acres and are near the recent Rosebank/ Lochnagar discovery in the United Kingdom. The company has a 40 percent interest and will be operator.

Mexico: In September 2004, ChevronTexaco was awarded authorization from the Mexican Environment and Natural Resources Secretariat for its Environmental Impact Assessment and Risk Assessment for the construction of a proposed LNG receiving and regasification terminal offshore Baja California and, in December, was awarded a natural gas storage permit from the Mexican Regulatory Energy Commission. Also in 2004, the company received notice from the Mexican Communication and Transport Secretariat, through its Port Authority, that it was the winner of the public licensing round for the offshore port terminal.

Norway: At the Draugen Field, where ChevronTexaco holds about an 8 percent interest, the company’s share of production during 2004 was 11,000 barrels of crude oil per day.

Russia: In September 2004, the company and OAO Gazprom signed a six-month memorandum of understanding to jointly undertake feasibility studies for the possible implementation of projects in Russia and the United States. This represents a possible opportunity to participate in the development of the vast natural gas and crude oil resource base in Russia and to develop a close partnership with Russia’s largest natural gas producer.

Trinidad and Tobago: The company has a 50 percent nonoperated interest in four blocks offshore Trinidad. Net natural gas production in 2004 averaged 135 million cubic feet per day. In 2005, the company announced the successful exploration drilling results at the offshore Manatee 1 exploration well in Block 6d. ChevronTexaco operates and holds a 50 percent interest in the well.


		United Kingdom: In the United Kingdom, the company’s total daily net production in 2004 from several fields was 106,000 barrels of crude oil and 340 million cubic feet of natural gas. Daily net production at the operated and 85 percent-owned Captain Field was 56,000 barrels of crude oil. The company’s share of net daily production in 2004 at the co-operated and 32 percent-owned Britannia Field was about 9,000 barrels of crude oil and 195 million cubic feet of natural gas. Development drilling at Britannia is expected to continue for several more years. At the Alba Field in the North Sea, where ChevronTexaco holds a 21 percent interest and operatorship, daily net production averaged 14,000 barrels of crude oil and 3 million cubic feet of natural gas. The operated and 50 percent-owned Erskine Field had net daily crude oil production of 8,000 barrels and net natural gas production of 41 million cubic feet. A crude oil and natural gas discovery was made in the fourth quarter 2004 at the offshore 40 percent-owned and operated Rosebank/ Lochnagar well (213/27-1Z) in the Faroe-Shetland Channel. Further appraisal drilling is planned for 2005.

ChevronTexaco holds a 19 percent interest in Clair, a nonoperated development. Platform and pipeline installation has been successfully completed. One well has been pre-drilled, and over 20 production and water injection wells are to be drilled and completed between late 2004 and early 2008. Initial production began in February 2005 and is expected to reach an average net daily production of 12,000 barrels of crude oil and 3 million cubic feet of natural gas by 2006. Initial recognition of proved reserves was in 2001. Some reserves were reclassified from proved undeveloped to proved developed in late 2004. Further reclassifications will occur through 2008 related to planned development drilling. Clair has an expected field life of over 20 years.

Three producing assets, Galley, Orwell and Statfjord fields, were sold in the first half 2004. The impact of these sales on 2004 U.K. net daily production was 12,000 barrels of crude oil and 19 million cubic feet of natural gas.

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. Total production in 2004 averaged

113,000 barrels of crude oil per day. The company also has production at the 63 percent-owned LL-652 Field located in Lake Maracaibo. Net production in 2004 averaged 10,000 barrels of oil-equivalent per day. The company operates at LL-652 under a risked service agreement.

The company also has exploration activity in two blocks offshore Plataforma Deltana. In Block 2, which includes Loran Field, two exploratory wells were drilled successfully in 2004. Proved reserves have not been recognized for this project. The company is operator and holds a 60 percent interest in Block 2. Also in August 2004, the company was awarded a license for Block 3, for which the company will be operator and holds a 100 percent interest. An exploration program for Block 3 is planned for 2005.

f) Affiliate Operations

Kazakhstan: The company holds a 50 percent interest in Tengizchevroil (TCO), which is developing the Tengiz and Korolev crude oil fields located in western Kazakhstan, under a 40-year concession that expires in 2033. Net oil-equivalent production averaged 178,000 barrels per day in 2004.

TCO is currently undertaking a significant expansion composed of two integrated projects referred to as the Sour Gas Injection (SGI)/Second Generation Project (SGP). At a total cost in excess of $4 billion, the expansion is designed to increase TCO’s crude oil production capacity from 298,000 barrels per day to between 430,000 and 500,000 barrels per day by late 2006, depending on the final effects of the SGI.

SGP involves the construction of a large processing train for treating crude oil and the associated sour gas. The SGP design is based on the same conventional technology employed in the existing processing trains. In addition to new processing capacity, SGP involves drilling and/or completing 55 production wells in the Tengiz and Korolev reservoirs to generate the volumes required for the new processing train. Proved undeveloped reserves associated with SGP were recognized in 2001. Some of these reserves were reclassified to proved developed in 2004 based upon completion of certain project milestones. Over the next decade, ongoing field development is expected to result in the maturation of the current proved undeveloped reserves to proved developed.

SGI involves taking a portion of the rich, sour gas separated from the crude oil production at the SGP processing train and re-injecting it into the Tengiz and Korolev reservoirs. ChevronTexaco expects that SGI will have two key effects. First, SGI will reduce the sour gas processing capacity otherwise required at SGP, thereby increasing liquid production capacity and lowering the quantities of sulfur and gas that would otherwise be generated. Second, over time it is expected that SGI will increase production efficiency and recoverable volumes due to the maintenance of higher reservoir pressure from the gas re-injection. Between 2006 and 2008, the company anticipates recognizing additional proved reserves associated with the SGI expansion. The primary SGI risks include uncertainties about compressor performance associated with injecting high-pressure sour gas and subsurface responses to injection.

Essentially all of TCO’s production is exported through the CPC pipeline that runs from Tengiz in Kazakhstan to tanker loading facilities at Novorossiysk on the Russian coast of the Black Sea. CPC, which is expected to be expanded in stages through the end of 2008, is anticipated to fully accommodate TCO expansion volumes by the end of 2007. TCO is currently pursuing alternate transportation routes to accommodate expansion volumes prior to the end of 2007 as necessary.

Venezuela: ChevronTexaco has a 30 percent interest in the Hamaca heavy oil production and upgrading project located in Venezuela’s Orinoco Belt. The crude oil upgrading began in October 2004. The facility is expected to reach design capacity in the first quarter 2005 to process 190,000 barrels per day of heavy crude oil (8.5° API) and upgrade into 180,000 barrels of lighter, higher-value crude oil (26° API). In 2004, net production averaged 24,000 barrels of crude oil per day.

Petroleum — Sale of Natural Gas and Natural Gas Liquids

The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. Outside the United States, the majority of the company’s natural gas sales occur in 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-10 in Management’s Discussion and Analysis of Financial Condition and Results of Operations for further information on the company’s natural gas and natural gas liquids sales volumes.

Petroleum — Refining Operations

Distillation operating capacity utilization in 2004, adjusted for sales and closures, averaged 91 percent in the United States (including asphalt plants) and 89 percent worldwide (including affiliates), compared with 91 percent in the United States and 88 percent worldwide in 2003. ChevronTexaco’s capacity utilization at its U.S. fuels refineries (i.e., excluding asphalt plants) averaged 96 percent in 2004, compared with 95 percent in 2003. Capacity utilization at the company’s 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 89 percent and 85 percent in 2004 and 2003, respectively. The company processed imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 81 percent and 75 percent of ChevronTexaco’s U.S. refinery inputs in 2004 and 2003, respectively.

In July 2004, the company acquired an additional interest in the Singapore Refining Company Pte. Ltd. (SRC), increasing ownership from 33 percent to 50 percent. The additional interest in SRC is expected to strengthen the company’s existing strategic position in the Asia-Pacific area, one of the company’s core markets.

The company’s U.S. West Coast and Gulf Coast refineries produce low sulfur fuels that meet 2006 federal government specifications. Investments required to produce low sulfur fuels in Europe and Canada were completed by the end of 2004 while clean fuel projects in South Africa and Australia are scheduled to be completed in 2005.

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 in Thousands of Barrels per Day)


		December 31, 2004				Refinery Inputs

				Operable
Locations		Number		Capacity		2004		2003		2002

Pascagoula	Mississippi		1		325		312		301		329
El Segundo	California		1		260		234		242		251
Richmond	California		1		225		233		235		187
El Paso¹	Texas		–		–		–		36		61
Kapolei	Hawaii		1		54		51		52		53
Salt Lake City	Utah		1		45		42		40		43
Other²			2		96		42		45		55

Total Consolidated Companies — United States			7		1,005		914		951		979

Pembroke	United Kingdom		1		210		209		175		204
Cape Town	South Africa		1		112		62		72		74
Burnaby, B.C.	Canada		1		52		49		50		51
Batangas³	Philippines		–		–		–		49		59
Colón⁴	Panama		–		–		–		–		27
Escuintla⁴	Guatemala		–		–		–		–		11

Total Consolidated Companies — International			3		374		320		346		426
Equity Affiliates⁵	Various Locations		11		833		724		694		674

Total Including Affiliates — International			14		1,207		1,044		1,040		1,100

Total Including Affiliates — Worldwide			21		2,212		1,958		1,991		2,079


	¹	ChevronTexaco sold its interest in the El Paso Refinery in August 2003.
	²	Refineries in Perth Amboy, New Jersey, and Portland, Oregon, are primarily asphalt plants.
	³	ChevronTexaco ceased refining operations at the Batangas Refinery in November 2003 in advance of the refinery’s conversion into a finished-product terminal.
	⁴	ChevronTexaco ceased refining operations at the Panama and Guatemala refineries in July 2002 and September 2002, respectively. The Guatemala facility was converted to terminal operations in 2002. The Panama facility was converted to a terminaling facility in 2003.
	⁵	ChevronTexaco increased its ownership interest in the Singapore Refining Company Pte. Ltd. from 33 percent to 50 percent in July 2004. This increased the company’s share of operable capacity at December 31, 2004 by about 48,000 barrels per day.

Petroleum — Sale of Refined Products

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 affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ending December 31, 2004.

Refined Products Sales Volumes¹

(Thousands of Barrels per Day)


		2004		2003		2002

United States
	Gasolines		701		669		680
	Jet Fuel		302		314		352
	Gas Oils and Kerosene		218		196		259
	Residual Fuel Oil		148		123		177
	Other Petroleum Products²		137		134		132

	Total United States		1,506		1,436		1,600

International³
	Gasolines		717		643		620
	Jet Fuel		250		228		207
	Gas Oils and Kerosene		805		780		783
	Residual Fuel Oil		463		487		416
	Other Petroleum Products²		167		164		149

	Total International		2,402		2,302		2,175

Total Worldwide³			3,908		3,738		3,775


¹Includes buy/sell arrangements:	180	194	197
²Principally naphtha, lubricants, asphalt and coke.
³Includes equity affiliates.

In the United States, the company markets under the Chevron and Texaco brands. The company supplies directly or through retailers and marketers almost 9,000 branded motor vehicle retail outlets, concentrated in the southern, eastern, southwestern and western states. Approximately 700 of the outlets are company-owned or -leased stations. By the end of the year, the company was supplying more than 1,000 Texaco retail sites, primarily in the Southeast. The Company plans to supply additional sites in the Southeast and West during 2005.

Outside of the United States, ChevronTexaco supplies directly or through retailers and marketers approximately 16,700 branded service stations, including affiliates, in nearly 90 countries. In Canada, primarily in British Columbia, the company markets under the Chevron brand name. In Europe, the company has marketing operations under the Texaco brand in the United Kingdom, Ireland, the Netherlands, Belgium, Luxembourg and the Canary Islands. In West Africa, the company operates or leases to retailers in Cameroon, Côte d’Ivoire, Nigeria, Republic of Congo, Togo and Benin. In these regions, the company mainly uses the Texaco brand name. The company also operates across the Caribbean, Central America, and South America, with a significant presence in Brazil, using the Texaco brand name. In the Asia-Pacific region, Southern, Central and East Africa, Egypt, and Pakistan, ChevronTexaco uses the Caltex brand name.

The company also operates through affiliates under various brand names. In Denmark and Norway, the company operates through its 50 percent-owned affiliate, HydroTexaco, using the Y-X and Uno-X brands. In the United Arab Emirates, the company operates through its 40-percent-owned Emirates Petroleum Products Co. joint venture, using the EPPCO brand. In South Korea, the company operates through its 50-percent-owned affiliate, LG Caltex, using the LG Caltex brand. This brand name will become GS Caltex effective March 31, 2005. The company’s 50-percent-owned affiliate in Australia operates primarily using the Caltex brand.

Throughout 2004, the company continued the marketing and sale of service station sites. Worldwide, dispositions totaling nearly 1,600 sites occurred as part of a decapitalization program in 2003 and 2004. In most cases, current sales volumes will continue through branded sales agreements.

In addition to the above activities, the company manages other marketing businesses globally. In global aviation fuel marketing, the company markets 500,000 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 the United States. ChevronTexaco markets an extensive line of lubricant products in about 170 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, 2004


		Net Mileage¹

United States:
	Crude Oil²		2,189
	Natural Gas		2,154
	Petroleum Products		5,330

	Total United States		9,673
International:
	Crude Oil²		431
	Natural Gas		767
	Petroleum Products		567

	Total International		1,765

Worldwide			11,438


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) operates a crude oil export pipeline from the Tengiz Field in Kazakhstan to the Russian Black Sea port of Novorossiysk. At the end of 2004, CPC had 10 transportation agreements in place and was transporting 550,000 barrels of crude oil per day from the Caspian region. Russian crude oil entered CPC in late 2004, and is forecasted to rise to about 120,000 barrels per day during 2005, bringing the pipeline capacity to 670,000 barrels per day.

The pipeline system is expandable to 1.4 million barrels per day with additional pump stations and tanks. CPC is in the initial planning stages of expanding the system. Expansion is expected to be completed in phases, with a total cost estimated at $2 billion. Full build-out to 1.4 million barrels per day is currently scheduled to be complete by the end of 2008 with additional planned capacity to begin operating in 2006 and 2007. ChevronTexaco has a 15 percent ownership interest in CPC.

Tankers: ChevronTexaco’s controlled seagoing fleet at December 31, 2004, is summarized in the following table. All controlled tankers were utilized in 2004. In addition, at any given time, the company has approximately 70 vessels under a voyage basis or as time charters of less than one year.

Controlled Tankers at December 31, 2004

U.S. Flag

Foreign Flag Number

Cargo Capacity

Number

(Millions of Barrels)

Number

(Millions of Barrels)

Owned

0.8

–

Bareboat Chartered

–

22.3

Time Chartered*

–

10.1

Total

0.8

32.4


*	One year or greater.

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 2004, the company’s U.S. flag fleet was engaged primarily in transporting refined products between the Gulf Coast and the East Coast, and from California refineries to terminals on the West Coast and in Alaska and Hawaii.

The international 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.

In addition to the vessels described above, the company owns a one-sixth interest in each of seven liquefied natural gas (LNG) tankers transporting cargoes for the North West Shelf (NWS) project in Australia. In early 2004, the company assumed full operatorship of one of the tankers, the Northwest Swan, on behalf of the project’s participants. Additionally, the NWS project has two LNG tankers under long-term time charter.

The Federal Oil Pollution Act of 1990 requires the scheduled phase-out, by year-end 2010, of all single-hull tankers trading to U.S. ports or transferring cargo in waters within the U.S. Exclusive Economic Zone. This has raised the demand for double-hull tankers. By the end of 2004, ChevronTexaco had a total of 18 company-operated double-hull tankers in operation. The company is a member of many oil-spill-response cooperatives in areas around the world in which it operates.

Chemicals

Chevron Phillips Chemical Company LLC (CPChem) is 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.

In 2004, along with its Saudi partner, CPChem secured approvals to proceed with construction of an integrated, world-scale styrene facility, along with the expansion of an existing, adjacently located aromatics plant in Al Jubail, Saudi Arabia. This $1.2 billion project is scheduled for completion in the first half of 2008.

Also during 2004, CPChem continued the development of the Q-Chem II and Ras Laffan ethylene projects in Qatar. Final approvals by the project partners for this world-scale olefins and polyolefins development are expected in 2005.

ChevronTexaco’s Oronite brand fuel and lubricant additives business is a leading developer, manufacturer and marketer of performance additives for fuels and lubricating oils. The company owns and operates facilities in the United States, France, the Netherlands, Singapore and Japan and has equity interests in facilities in India and Mexico. In January 2005, the company announced it is closing its manufacturing plant in Brazil. The closure is expected to be completed by the end of 2005.

Coal

The company’s coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), owned and operated two surface mines, McKinley, in New Mexico, and Kemmerer, in Wyoming, and one underground mine, North River, in Alabama, at year-end 2004. In addition, final reclamation activities were under way at the York Canyon and Farco mines, located in New Mexico and Texas, respectively. 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 as well as in trading and transportation activities.

Sales of coal from P&M’s wholly owned mines and from its affiliates were 14.6 million tons, an increase of 9 percent from 2003. The increase was primarily a result of higher production at P&M’s surface mine located near Gallup, New Mexico.

At year-end 2004, P&M controlled approximately 167 million tons of developed and undeveloped coal reserves, including reserves of environmentally desirable low-sulfur coal. The company is contractually committed to deliver approximately 14 million tons of coal per year through the end of 2006 and believes it can satisfy these contracts from existing coal reserves.

Synthetic Crude Oil

In Canada, ChevronTexaco holds a 20 percent nonoperating interest in the Athabasca Oil Sands Project (AOSP). Bitumen is extracted from oil sands and upgraded into synthetic crude oil using hydroprocessing technology. The integrated operation at AOSP commenced in 2003 with ramp-up of production continuing in 2004. Total 2004 bitumen production averaged 134,000 barrels per day (about 27,000 net barrels). At full capacity in 2005, AOSP is expected to reach total production of 155,000 barrels per day.

Global Power Generation

ChevronTexaco’s Global Power Generation (GPG) has more than 20 years experience in developing and operating commercial power projects. With 13 power assets located in the United States and Asia, GPG manages the production of more than 3,300 megawatts of electricity in its facilities. All of the facilities are owned through joint ventures. The company operates efficient gas-fired cogeneration facilities, some of which produce steam for use in upstream operations to facilitate production of heavy oil.

Gas-to-Liquids

The 50-50 Sasol Chevron Global Joint Venture was established in October 2000 to develop a worldwide gas-to-liquids (GTL) business. In Nigeria, construction for the planned gas-to-liquids facility at Escravos is expected to begin in 2005, pending finalization of fiscal terms. Projects to build GTL plants are being considered for Qatar and Australia.

Research and Technology

The company’s Energy Technology Company delivers integrated technologies and services to the upstream, downstream and gas-based businesses. These activities include deepwater exploration and production systems, reservoir management and optimization, heavy oil recovery and upgrading, shallow-water production operations, gas-to-liquids processing, improved refining processes, and safe, incident-free plant operations.

Additionally, ChevronTexaco’s Technology Ventures Company focuses on identification, growth and commercialization of emerging technologies that have the potential to transform how energy is produced or consumed. The range of business spans early-stage investing of venture capital in emerging technologies to developing joint venture companies in new energy systems, such as hydrogen infrastructure, advanced battery systems, nano-materials and renewable energy applications.

ChevronTexaco’s research and development expenses were $242 million, $228 million and $221 million for the years 2004, 2003 and 2002, 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 to 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 2004, the company’s U.S. capitalized environmental expenditures were $145 million, representing approximately 5 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 2005, the company estimates U.S. capital expenditures for environmental control facilities will be approximately $240 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 on the company’s 2004 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-15 to FS-16, and on page FS-18 of this Annual Report on Form 10-K.

Website Access to SEC Reports

The company’s Internet website can be found at http://www.chevrontexaco.com/. Information contained on the company’s Internet website is not part of this Form 10-K 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 website, free of charge, soon after such reports are filed with or furnished to the SEC.

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


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-57 to FS-68 of this Annual Report on Form 10-K. Note 15, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-41 of this Annual Report on Form 10-K.


Item 3.	Legal Proceedings

None.


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

None.

Executive Officers of the Registrant at March 1, 2005


Name and Age

		Executive Office Held	Major Area of Responsibility

D. J. O’Reilly	58	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	58	Office of the Chairman since 2005 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	Office of the Chairman; Strategic Planning; Policy, Government and Public Affairs; Human Resources

J. E. Bethancourt	53	Executive Vice President since 2003 Executive Committee Member since 2003	Technology; Chemicals; Coal; Health, Environment and Safety

G. L. Kirkland	54	Executive Vice President since 2005 President of ChevronTexaco Overseas Petroleum Inc. from 2002 to 2004 Vice President from 2000 to 2004 President of Chevron U.S.A. Production Company from 2000 to 2002 Executive Committee Member from 2000 to 2001 and since 2005	Worldwide Exploration and Production Activities and Global Gas Activities

S. Laidlaw	49	Executive Vice President since 2003 Executive Committee Member since 2003	Business Development

P. A. Woertz	51	Executive Vice President since 2001 Vice President since 1998 President of Chevron Products Company from 1998 to 2001 Executive Committee Member since 1998	Global Refining, Marketing, Lubricants, and Supply and Trading

S. J. Crowe	57	Vice President and Chief Financial Officer since 2005 Vice President and Comptroller from 2001 to 2004 Vice President and Comptroller of Chevron Corporation from 1996 to 2001 Executive Committee Member since 2005	Finance

C. A. James	50	Vice President and General Counsel since 2002 Executive Committee Member since 2002	Law

J. S. Watson	48	President of ChevronTexaco Overseas Petroleum Inc. since 2005 Vice President and Chief Financial Officer from 2000 to 2004 Executive Committee Member from 2000 to 2004	Overseas Exploration and Production

R. I. Wilcox	59	President, ChevronTexaco Exploration & Production Company since 2002 Vice President since 2002	North American Exploration and Production

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


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

S. J. Crowe	-	Comptroller, Chevron Corporation – 1996
	-	Vice President and Comptroller, Chevron Corporation – 2000
	-	Vice President and Comptroller, ChevronTexaco Corporation – 2001

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 U.S.A. Production Company – 2000
	-	President, ChevronTexaco Overseas Petroleum Inc. – 2002

S. Laidlaw	-	President and Chief Operating Officer, Amerada Hess – 2001
	-	Chief Executive Officer, Enterprise Oil plc – 2002
	-	Executive Vice President, ChevronTexaco Corporation – 2003

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

PART II

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

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-22 of this Annual Report on Form 10-K.

CHEVRONTEXACO CORPORATION

ISSUER PURCHASES OF EQUITY SECURITIES

Maximum

Total Number of

Number of Shares

Total Number

Average

Shares Purchased as

that May Yet Be

of Shares

Price Paid

Part of Publicly

Purchased Under

Period

Purchased (1)(2)

per Share (2)

Announced Program

the Program

Oct. 1 – Oct. 31, 2004

2,995,294

54.36

2,345,100

—

Nov. 1 – Nov. 30, 2004

5,838,650

53.67

5,545,600

—

Dec. 1 – Dec. 31, 2004

6,348,653

52.69

6,158,821

—

Total Oct. 1 – Dec 31, 2004

15,182,597

53.40

14,049,521

)


(1)	Includes 74,679 common shares repurchased during the three-month period ended December 31, 2004 from company employees for required personal income tax withholdings on the individual’s exercise of the stock options issued to management and employees under the company’s broad-based employee stock options, long-term incentive plans and former Texaco Inc. stock option plans. Additionally, includes 1,058,397 shares delivered or attested to in satisfaction of the exercise price by holders of certain former Texaco Inc. employee stock options exercised during the three-month period ended December 31, 2004.

(2)	All share and per share value amounts reflect the two-for-one stock split in September 2004.

(3)	On March 31, 2004, the company announced a common stock repurchase program. Acquisitions of up to $5 billion will be made from time to time at prevailing prices as permitted by securities laws and other requirements, and subject to market conditions and other factors. The program will occur over a period of up to three years and may be discontinued at any time. Through December 31, 2004, $2.1 billion has been expended to repurchase 42,324,089 shares since the common stock repurchase program began.

Item 6. Selected Financial Data

The selected financial data for years 2000 through 2004 are presented on page FS-57 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-14 and Note 8 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-35.

Item 8. Financial Statements and Supplementary Data

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

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

None.

Item 9A. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

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-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of December 31, 2004, have concluded that as of December 31, 2004, the company’s disclosure controls and procedures were effective and designed to provide reasonable assurance that material information relating to the company and its consolidated subsidiaries required to be included in the company’s periodic filings under the Exchange Act would be made known to them by others within those entities.

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


	The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the company’s management concluded that its internal control over financial reporting was effective as of December 31, 2004.

	The company management’s assessment of the effectiveness of its internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.


	During the quarter ended December 31, 2004, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.

Item 9B. Other Information


	*Disclosure Regarding Nominating Committee Functions and Communications Between Security Holders and Boards of Directors*

No change.


	*Rule 10b5-1 Plan Elections*

No rule 10b5-1 plans were adopted by executive officers or directors for the period that ended on December 31, 2004.

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 2005 Annual Meeting of Stockholders and 2005 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), in connection with the company’s 2005 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 29 and 30 of this Annual Report on Form 10-K for information about Executive Officers of the company.

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

The information contained under the heading “Stock Ownership Information – Section 16(a) Beneficial Ownership Reporting Compliance” in the Notice of the 2005 Annual Meeting of Stockholders and 2005 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2005 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.

The company has adopted a code of business conduct and ethics for directors, officers (including the company’s Chief Executive Officer, Chief Financial Officer and Comptroller) and employees, known as the Business Conduct and Ethics Code. The code is available on the company’s Internet Web site at http://www.chevrontexaco.com/. Any amendments to the Business Conduct and Ethics Code will be posted on the company’s Web site.


Item 11.	Executive Compensation

The information appearing under the headings “Executive Compensation” and “Directors Compensation” in the Notice of the 2005 Annual Meeting of Stockholders and 2005 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2005 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 2005 Annual Meeting of Stockholders and 2005 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2005 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 2005 Annual Meeting of Stockholders and 2005 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2005 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 2005 Annual Meeting of Stockholders and 2005 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2005 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.


Item 14.	Principal Accounting Fees and Services

The information appearing under the headings “Ratification of Independent Registered Public Accounting Firm – Principal Accountant Fees and Services” and “Ratification of Independent Registered Public Accounting Firm – Audit Committee Pre-Approval Policies and Procedures” in the Notice of the 2005 Annual Meeting of Stockholders and 2005 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2005 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.

PART IV

Item 15. Exhibits, Financial Statement Schedules


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


	(1) Financial Statements:


		Page(s)

Report of Independent Registered Public Accounting Firm — PricewaterhouseCoopers LLP		FS-24

Consolidated Statement of Income for the three years ended December 31, 2004		FS-25

Consolidated Statement of Comprehensive Income for the three years ended December 31, 2004		FS-26

Consolidated Balance Sheet at December 31, 2004 and 2003		FS-27

Consolidated Statement of Cash Flows for the three years ended December 31, 2004		FS-28

Consolidated Statement of Stockholders’ Equity for the three years ended December 31, 2004		FS-29

Notes to Consolidated Financial Statements		FS-30 to FS-55


	(2) Financial Statement Schedules:


	We have included on page 35 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.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Millions of Dollars


	Year Ended December 31

	2004			2003			2002

Employee Termination Benefits:

Balance at January 1	$	341		$	336		$	665

Additions charged to expense		29			295			71

Payments		(233	)		(290	)		(400	)


Balance at December 31	$	137		$	341		$	336


Allowance for Doubtful Accounts:

Balance at January 1	$	229		$	225		$	183

Additions charged to expense		36			52			131

Bad debt write-offs		(46	)		(48	)		(89	)


Balance at December 31	$	219		$	229		$	225


Deferred Income Tax Valuation Allowance:*

Balance at January 1	$	1,553		$	1,740		$	1,512

Additions charged to deferred income tax expense		714			375			776

Deductions credited to deferred income tax expense		(606	)		(562	)		(548	)


Balance at December 31	$	1,661		$	1,553		$	1,740


*	See also Note 17 to the Consolidated Financial Statements beginning on page FS-42.

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 3rd day of March, 2005.


	ChevronTexaco Corporation


	By	/s/ David J. O’Reilly



	David J. O’Reilly, Chairman of the Board
	and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 3rd day of March, 2005.


		Principal Executive Officers
		(and Directors)		Directors

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

		/s/Peter J. Robertson Peter J. Robertson, Vice Chairman of the Board		Robert E. Denham* Robert E. Denham

				Robert J. Eaton* Robert J. Eaton

				Sam Ginn* Sam Ginn

		Principal Financial Officer

		/s/Stephen J. Crowe Stephen J. Crowe, Vice President, Finance and Chief Financial Officer		Carla A. Hills* Carla A. Hills

				Franklyn G. Jenifer* Franklyn G. Jenifer

		Principal Accounting Officer

		/s/Mark A. Humphrey Mark A. Humphrey, Vice President and Comptroller		J. Bennett Johnston* J. Bennett Johnston

				Sam Nunn* Sam Nunn

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

				Carl Ware* Carl Ware

Index to Management’s Discussion and Analysis
Consolidated Financial Statements and Supplementary Data


Management’s Discussion and Analysis of Financial Condition and Results of Operations		FS-2 to FS-21

Quarterly Results and Stock Market Data		FS-22

Report of Management		FS-23

Reports of Independent Registered Public Accounting Firm		FS-24

Consolidated Statement of Income		FS-25

Consolidated Statement of Comprehensive Income		FS-26

Consolidated Balance Sheet		FS-27

Consolidated Statement of Cash Flows		FS-28

Consolidated Statement of Stockholders’ Equity		FS-29

Notes to Consolidated Financial Statements		FS-30 to FS-55

Five-Year Financial Summary		FS-57

Supplemental Information on Oil and Gas Producing Activities		FS-57 to FS-68

FS-1


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

KEY FINANCIAL RESULTS


Millions of dollars, except per-share amounts	2004			2003			2002

Net Income	$	13,328		$	7,230		$	1,132
Per Share Amounts:*
Net Income – Basic	$	6.30		$	3.48		$	0.53
Net Income – Diluted	$	6.28		$	3.48		$	0.53
Dividends	$	1.53		$	1.43		$	1.40
Sales and Other Operating Revenues	$	150,865		$	119,575		$	98,340
Return on:
Average Capital Employed		25.8	%		15.7	%		3.2	%
Average Stockholders’ Equity		32.7	%		21.3	%		3.5	%


*	2003 and 2002 restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in 2004.

INCOME FROM CONTINUING OPERATIONS BY MAJOR OPERATING AREA


Millions of dollars	2004			2003			2002

Income From Continuing Operations
Upstream – Exploration and Production
United States	$	3,868		$	3,160		$	1,703
International		5,622			3,199			2,823

Total Exploration and Production		9,490			6,359			4,526

Downstream – Refining, Marketing and Transportation
United States		1,261			482			(398	)
International		1,989			685			31

Total Refining, Marketing and Transportation		3,250			1,167			(367	)

Chemicals		314			69			86
All Other		(20	)		(213	)		(3,143	)

Income From Continuing Operations	$	13,034		$	7,382		$	1,102
Income From Discontinued Operations – Upstream		294			44			30

Income Before Cumulative Effect of Changes in Accounting Principles	$	13,328		$	7,426		$	1,132
Cumulative Effect of Changes in Accounting Principles		–			(196	)		–

Net Income^*	$	13,328		$	7,230		$	1,132

^*Includes Foreign Currency Effects:	$	(81	)	$	(404	)	$	(43	)

In 2003, net income included charges of $200 million for the cumulative effect of changes in accounting principles, related to the adoption of Financial Accounting Standards Board (FASB) Statement No. 143 (FAS 143), “Accounting for Asset Retirement Obligations.” Refer to Note 25 of the Consolidated Financial Statements on page FS-53 for additional discussion.

Net income in each period presented included amounts for matters that management characterized as “special items,” as described in the table that follows. These amounts, because of their nature and significance, are identified separately to help explain the changes in net income and segment income between periods and to help distinguish the underlying trends for the company’s core businesses. Special items are discussed in detail for each major operating area in the “Results of Operations” section beginning on page FS-6. “Restructuring and Reorgani-

zations” is described in detail in Note 12 to the Consolidated Financial Statements on page FS-39.

SPECIAL ITEMS


Millions of dollars - Gains (charges)	2004			2003			2002

Asset Dispositions
Continuing Operations	$	960		$	122		$	–
Discontinued Operations		257			–			–
Litigation Provisions		(55	)		–			(57	)
Asset Impairments/Write-offs		–			(340	)		(485	)
Dynegy-Related		–			325			(2,306	)
Tax Adjustments		–			118			60
Restructuring and Reorganizations		–			(146	)		–
Environmental Remediation Provisions		–			(132	)		(160	)
Merger-Related Expenses		–			–			(386	)

Total	$	1,162		$	(53	)	$	(3,334	)

BUSINESS ENVIRONMENT AND OUTLOOK

As shown in the “Special Items” table, net special gains of $1.2 billion, associated mainly with the disposition of non-strategic upstream assets, benefited income in 2004. 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 page FS-11 for a discussion of the company’s investment in Dynegy.

The special items recorded in 2002 through 2004 are not indicative of any future trends of events or their impact on future earnings. Because of the nature of special item-related events, the company may not always be able to anticipate their occurrence or associated effects on income in any period. Apart from the effects of special-item gains and charges, the company’s earnings depend largely on the profitability of its upstream – exploration and production – and downstream – refining, marketing and transportation – business segments. The single largest variable that affects the company’s results of operations is crude oil prices. Overall earnings trends are typically less affected by results from the company’s commodity chemicals segment and other activities and investments.

The company’s long-term competitive position, particularly given the capital-intensive and commodity-based nature of the industry, is closely associated with the company’s ability to invest in projects that provide adequate financial returns and to manage operating expenses effectively. Creating and maintaining an inventory of projects depends on many factors, including obtaining rights to explore, develop and produce hydrocarbons in promising areas, drilling success, the ability to bring long-lead-time capital-intensive projects to completion on budget and schedule, and efficient and profitable operation of mature properties.

The company also continuously evaluates opportunities to dispose of assets that are not key to providing sufficient long-term value and to acquire assets or operations complementary to its asset base to help sustain the company’s growth. In addition to the asset-disposition and restructuring plans announced in 2003, which generated $3.7 billion of sales proceeds in 2004, other such plans may also occur in future periods and result in significant gains or losses. Refer to the “Operating Developments” section on page FS-4 for a discussion that includes references to the company’s asset disposition activities.

FS-2

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 external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damages and disruptions, competing fuel prices, and regional supply interruptions that may be caused by military conflicts, civil unrest or political uncertainty. Moreover, any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments and attempts to manage risks in operating its facilities and business. Longer-term trends in earnings for this segment are also a function of other factors besides price fluctuations, including changes in the company’s crude oil and natural gas production levels and the company’s ability to find or acquire and efficiently produce crude oil and natural gas reserves.

The level of operating expenses associated with the efficient production of oil and gas can also be subject to external factors beyond the company’s control. External factors include not only the general level of inflation but also prices charged by the industry’s product- and service-providers, which can be affected by the volatility of the industry’s own supply and demand conditions for such products and services. Operating expenses can also be affected by uninsured damages to production facilities caused by severe weather or civil unrest.

(LINE GRAPH)

Industry price levels for crude oil reached record highs during 2004. For example, the price for West Texas Intermediate (WTI) crude oil, one of the benchmark crudes, reached $55 per barrel in October 2004. WTI prices for the full year averaged $41 per barrel, an increase of approximately $10 per barrel from 2003. The WTI spot price per barrel at the end of February 2005 was approximately $51. These relatively high industry prices reflected, among other things, increased demand from higher economic growth, particularly in Asia and the United States, the heightened level of geopolitical uncertainty in many areas of the world, crude oil supply concerns in the Middle East and other key producing regions, and production shut in for repairs following Hurricane Ivan in the Gulf of Mexico in September 2004.

During most of 2004, the differential in prices between high quality, light-sweet crude oils, such as the U.S. benchmark

WTI, and the heavier crudes was unusually wide. The upward trend in prices in 2004 for lighter crude oils tracked the increased demand for light products, as all refineries could process these higher quality crudes. However, the demand and price for the heavier crudes were dampened due to the limited number of refineries that are able to process this lower quality feedstock. The company produces heavy crude oil (including volumes under an operating service agreement) in California, Indonesia, the Partitioned Neutral Zone (between Saudi Arabia and Kuwait) and Venezuela.

Natural gas prices, particularly in the United States, were also higher in 2004 than in 2003. Benchmark prices in 2004 for Henry Hub U.S. natural gas peaked in October 2004 above $8.50 per thousand cubic feet (MCF). For the full year, prices averaged nearly $6.00 per MCF, compared with $5.50 in 2003. At the end of February 2005, the Henry Hub spot price was about $6.10 per MCF.

As compared with the supply and demand factors for natural gas in the United States and the resultant trend in the Henry Hub benchmark prices, certain other regions of the world in which the company operates have significantly different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices for the company’s production of natural gas. (Refer to the table on page FS-10 for the company’s average natural gas prices for the United States and international regions.) Additionally, excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the United States and other developed markets because of lack of infrastructure and the difficulties in transporting natural gas.

To help address this regional imbalance between supply and demand for natural gas, ChevronTexaco and other companies in the industry are planning increased investments in long-term projects in areas of excess supply to install infrastructure to produce and liquefy natural gas for transport by tanker and additional investment to regasify the product in markets where demand is strong and supplies are not as plentiful. Due to the

(BAR CHARTS)

FS-3


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

significance of the overall investment in these long-term projects, the natural gas sales prices in the areas of excess supply (before the natural gas is transferred to a company-owned or third-party processing facility) are expected to remain well below sales prices for natural gas that is produced much nearer to areas of high demand and that can be transported in existing natural gas pipeline networks (as in the United States).

Partially offsetting the benefit of higher crude oil and natural gas prices in 2004 was a 5 percent decline in the company’s worldwide oil-equivalent production from the prior year, including volumes produced from oil sands and production under an operating service agreement. The decrease was largely the result of lower production in the United States due to normal field declines, property sales and production curtailments resulting from damages to producing operations caused by Hurricane Ivan. International oil-equivalent production was down marginally between years. Refer also to pages FS-7 for additional discussion and detail of production volumes worldwide.

The level of oil-equivalent production in future periods is uncertain, in part because of OPEC production quotas and the potential for local civil unrest and changing geopolitics that could cause production disruptions. Approximately 25 percent of the company’s net oil-equivalent production in 2004, including volumes produced from oil sands and under an operating service agreement, was in the OPEC-member countries of Indonesia, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. Although the company’s production level during 2004 was not constrained in these areas by OPEC quotas, future production could be affected by OPEC-imposed limitations. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. Refer to pages FS-4 through FS-6 for discussion of the company’s major upstream projects.

In certain onshore areas of Nigeria, approximately 45,000 barrels per day of the company’s net production capacity has been shut in since March 2003 because of civil unrest and damage to production facilities. The company has adopted a phased plan to restore these operations and has begun production-resumption efforts in certain areas.

As a result of Hurricane Ivan in September 2004, production in the fourth quarter was about 60,000 barrels per day lower than it otherwise would have been. Damages to producing facilities are expected to restrict oil-equivalent production in the first quarter 2005 by approximately 35,000 barrels per day. Most of the remaining shut-in production is expected to be restored in the second quarter of 2005.

Downstream Refining, marketing and transportation earnings are closely tied to regional demand for refined products and the associated effects on industry refining and marketing margins. The company’s core marketing areas are the West Coast of North America, the U.S. Gulf Coast, Latin America, Asia and sub-Saharan Africa.

Specific factors influencing the company’s profitability in this segment include the operating efficiencies and expenses of the refinery network, including the effects of any downtime due to planned and unplanned maintenance, refinery upgrade

projects and operating incidents. The level of operating expenses can also be affected by the volatility of charter expenses for the company’s shipping operations, which are driven by the industry’s demand for crude-oil tankers. Factors beyond the company’s control include the general level of inflation, especially energy costs to operate the refinery network.

Downstream earnings improved in 2004 compared with the prior year, primarily as a result of increased demand and higher margins for the industry’s refined products in most of the areas in which the company and its equity affiliates have operations. In 2004, refined-product margins in North America and Asia were at their highest level in recent years. Industry margins may be volatile in the future, depending primarily on price movements for crude oil feedstocks, the demand for refined products, inventory levels, refinery maintenance and mishaps, and other factors.

Chemicals Earnings in the petrochemicals segment are closely tied to global chemical demand, inventory levels and plant capacities. Additionally, feedstock and fuel costs, which tend to follow crude oil and natural gas price movements, influence earnings in this segment.

Earnings improved in 2004 compared with 2003 primarily from the results of the company’s 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate, which recorded higher margins and sales volumes for commodity chemicals and higher equity affiliate income.

OPERATING DEVELOPMENTS

Key operating developments and other events during 2004 and early 2005 included:

Upstream

North America During 2004, the company closed on the sale of more than

300 producing properties and other assets in the United States and Canada, generating proceeds of $2.5 billion. These sales, which accounted for less than 10 percent of the oil-equivalent production and reserves in North America, were part of plans announced in 2003 to dispose of assets that did not provide sufficient long-term value to the company and to improve the overall competitive performance and operating efficiency of the company’s exploration and production portfolio.
In the Gulf of Mexico, the company awarded two major engineering contracts for the development of subsea systems and a floating production facility to advance the development of the operated and 58 percent-owned Tahiti prospect, a major deepwater discovery. A successful well test of the original discovery well was also conducted in 2004. Elsewhere in the

(BAR CHART)

FS-4

Gulf of Mexico, a deepwater crude oil discovery was announced at the operated and 50 percent-owned Jack prospect in Walker Ridge Block 759.

Angola In late 2004, first production was achieved at the Block 0 Sanha Bomboco project, which will help reduce natural-gas flaring.

Australia In mid-2004, the company announced a natural gas discovery at the wholly owned Wheatstone-1 well located offshore Western Australia. Production tests were completed in the third quarter 2004, and in early 2005 the company was evaluating development options.

Cambodia In January 2005, the company announced crude oil discoveries at four exploration wells in offshore Block A. ChevronTexaco is the operator of the block and holds a 55 percent interest.

China In August 2004, initial crude oil production occurred at the 16 percent-owned BZ 25-1 Field, located in Bohai Bay. Crude oil production also began late in 2004 at the HZ 19-3 Field, in which the company has a 33 percent working interest.

Faroe Islands In January 2005, the company was awarded five offshore exploration blocks in the Faroe Islands’ second offshore licensing round. The blocks are near the earlier Rosebank/Lochnagar discovery in the United Kingdom. The company has a 40 percent interest and will be the operator.

Kazakhstan The company’s first crude oil from Karachaganak Field was loaded at Russia’s Black Sea port of Novorossiysk in mid-2004. This represented the first shipment of Karachaganak crude oil through the Caspian Pipeline Consortium export pipeline that provides access to world markets.

Construction continued during 2004 by the company’s 50 percent-owned Tengizchevroil affiliate on Sour Gas Injection (SGI)/Second Generation Project (SGP), which is expected to increase total production from the current capacity of 298,000 barrels of crude oil per day to between 430,000 and 500,000 barrels per day by the end of 2006, with the expansion dependent upon the success of the SGI.

Libya In early 2005, the company was awarded onshore Block 177 in Libya’s first exploration license round under the Exploration and Production Sharing Agreement IV terms. The company was also made operator of the block with 100 percent equity. The events mark the company’s return to Libya after a 28-year absence.

Nigeria At the deepwater Agbami project, several milestones were achieved in 2004, including initial development drilling in the third quarter, and reaching a unitization agreement with other owners in the area. In early 2005, a contract for the construction of a floating production, storage and offshore loading platform was awarded. The project is being unitized, and the company’s equity will be about 68 percent.

The company was awarded a 100 percent contractor interest in the deepwater Nigeria Block OPL-247 in the eastern part of the Niger Delta in the second quarter 2004. Block 247 is adjacent to Block 222, which includes the company’s Usan and Ukot discoveries.

In the third quarter 2004, the company announced a crude oil discovery at the Usan 5 well. Additionally, in early 2005, hydrocarbons were encountered at the Usan 6 appraisal well. ChevronTexaco holds a 30 percent interest in the wells, both of which are located in OPL-222.

Nigeria — São Tomé and Príncipe Joint Development Zone (JDZ) The company was awarded the right in early 2004 to conduct exploration activities in deepwater Block 1 in the JDZ, offshore São Tomé and Príncipe and Nigeria. In early 2005, the company signed a production-sharing contract with the Joint

Development Authority, under which ChevronTexaco will be the operator with a 51 percent interest in the block.

Southern Africa The company announced a discovery in the deepwater area between Angola and the Republic of Congo at the Lianzi-1 exploration well in the third quarter 2004. The discovery, in the shared 14K/A-IMI Unit, is located in the same area as the previous Block 14 deepwater crude oil discoveries at Landana and Tombua in Angola. ChevronTexaco is the operator of the 14K/A-IMI Unit and holds about a 31 percent interest.

Russia In September 2004, the company and OAO Gazprom signed a six-month memorandum of understanding to jointly undertake feasibility studies for the possible implementation of projects in Russia and the United States. This represents a possible opportunity to participate in the development of the vast natural gas and crude oil resource base in Russia and to develop a close partnership with Russia’s largest natural gas producer.

Thailand The company announced successful exploration and appraisal drilling results in mid-2004 at Block G4/43, located in the Gulf of Thailand. Block G4/43 is adjacent to the company’s operated and 52 percent-owned Block B8/32.

Trinidad and Tobago In early 2005, the company announced successful exploration drilling results at the offshore Manatee 1 exploration well in Block 6d. ChevronTexaco operates and holds a 50 percent interest in this well.

United Kingdom In the third quarter 2004, production of first crude oil occurred at the 21 percent-owned Alba Extreme South Phase 2 project. Alba Field is located in Block 16/26, northeast of Aberdeen. In the fourth quarter, a crude oil and natural gas discovery was made at the offshore 40 percent-owned Rosebank/Lochnagar well (213/27-1Z) in the Faroe-Shetland Channel.

Venezuela In August 2004, the company was awarded an exploration license and 100 percent interest for Block 3 in Plataforma Deltana, an offshore area on Venezuela’s Atlantic continental shelf. The exploration rights added to the company’s existing Block 2 license in Venezuela and Block 6d in Trinidad and Tobago, across the border with Venezuela. Two exploration wells were successful during 2004 in the operated and 60 percent-owned Plataforma Deltana Block 2.

The company completed onshore construction of the 30 percent-owned Hamaca Project’s crude oil upgrading facility. This facility has the capacity to process 190,000 barrels per day of heavy crude oil and upgrade into 180,000 barrels per day of lighter higher-value crude oil. Upgrading began in October 2004.

Global Natural Gas Projects In Qatar, Sasol Chevron, ChevronTexaco’s 50-50 global joint venture with Sasol of South Africa, entered into a memorandum of understanding with Qatar Petroleum to expand the Oryx gas-to-liquids project and a letter of intent to examine GTL base oils opportunities in Qatar. Qatar Petroleum and Sasol Chevron also agreed to pursue an opportunity to develop a 130,000-barrel-per-day integrated gas-to-liquids project.

In Australia, the North West Shelf Venture began commissioning of a fourth LNG train in September 2004. This increased the venture’s LNG production capacity by approximately 50 percent during 2004. ChevronTexaco holds a one-sixth interest in the joint venture.

The company announced in the fourth quarter 2004 an agreement with other shareholders of the West African Gas Pipeline Co. Ltd. to move forward with the construction of a pipeline to be used for the transportation of natural gas more than 400 miles from Nigeria to customers in Ghana, Benin and Togo.

In early 2005, the company announced plans to conduct a feasibility study on a potential liquefied natural gas (LNG) project at Olokola in southwest Nigeria. Future decisions to move

FS-5


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

forward with Olokola LNG will depend on the results of the feasibility study.

In November 2004, ChevronTexaco and its partners in the Brass LNG Project awarded the contract for front-end engineering and design for a world-scale LNG plant to be located in Nigeria. The LNG plant will have two processing trains with potential processing capacity of 5 million metric tons each. ChevronTexaco is expected to supply a major amount of feed gas to the LNG project.

In Angola, front-end engineering and design work is scheduled to begin in the first half of 2005 for the construction of a multibillion dollar LNG processing plant that also will help eliminate natural gas flaring associated with crude oil producing operations. The company has a 36 percent ownership interest in the plant and will co-lead the project with the Angolan government’s national oil company.

In September 2004, the company was awarded authorization from the Mexican Environment and Natural Resources Secretariat for its Environmental Impact Assessment and Risk Assessment for a proposed LNG receiving and regasification terminal offshore Baja California, Mexico. In December 2004, the company was awarded a natural gas storage permit from the Mexican Regulatory Energy Commission for a proposed natural gas terminal. The company also received notice from the Mexican Communication and Transport Secretariat, through its Port Authority, that it won the public licensing round for the offshore port terminal.

In November 2004, the company announced it had plans to submit permit applications for a proposed LNG import terminal to be located at the company’s Pascagoula Refinery.

In December 2004, the company announced the finalization of a 20-year agreement for regasification capacity at the proposed Sabine Pass LNG terminal in Louisiana.

Downstream

Worldwide Reorganization In early 2004, the company’s downstream businesses began operating as global refining, marketing, and supply and trading businesses. Previously, these functions were aligned by the individual geographic areas in which the company operates. This realignment is targeted to improve operating efficiencies and financial performance.

Singapore Joint Venture In July 2004, the company acquired an additional interest in the Singapore Refining Company Pte. Ltd. (SRC), increasing its ownership from 33 percent to 50 percent. This additional interest in SRC is expected to strengthen ChevronTexaco’s existing strategic position in the Asia-Pacific area, one of its core markets.

China Joint Venture In January 2005, the company announced a preliminary agreement for a business partner in China to take a majority interest in the company’s existing joint venture that operates retail service stations in South China.

Asset Dispositions Throughout 2004, the company continued the marketing and sale of service station sites. Dispositions of about 1,600 sites occurred from the program’s inception in early 2003 through the end of 2004. In February 2005, the company announced a memorandum of understanding to negotiate the sale of approximately 140 service stations in the United Kingdom.

Texaco Brand Under terms of an agreement executed at the time of the merger with Texaco, the company regained non-

exclusive rights to use the Texaco brand in the United States on July 1, 2004, and resumed marketing gasoline under the Texaco retail brand in the United States in mid-2004. By the end of the year, the company was supplying more than 1,000 Texaco retail sites, primarily in the Southeast. The company plans to supply additional sites in the Southeast and West during 2005.

Chemicals

Saudi Arabia The company’s 50 percent-owned affiliate, CPChem, began construction of an integrated styrene facility and expansion of an adjacent aromatics plant at Al Jubail, Saudi Arabia, in the fourth quarter 2004. The project is scheduled for completion in the first half of 2008.

Other

Common Stock Dividends and Stock Repurchase Program In September 2004, the company increased its quarterly common stock dividend by 10 percent and immediately followed the dividend increase with a two-for-one stock split in the form of a stock dividend. In connection with a stock repurchase program initiated in April 2004, the company purchased 42,324,000 shares in the open market for $2.1 billion through December. Purchases through the end of February 2005 increased the total shares acquired to 47,969,000 shares for $2.4 billion. The repurchase program is in effect for up to three years from the date initiated for acquisitions of up to $5 billion.

RESULTS OF OPERATIONS

Major Operating 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. (Refer to Note 9 beginning on page FS-36 for a discussion of the company’s “reportable segments,” as defined in FAS 131, “Disclosures About Segments of an Enterprise and Related Information.”) To aid in the understanding of changes in segment income between periods, the discussion, when applicable, is in two parts – first, on underlying trends and second, on special-item gains and charges that tended to obscure these trends. In the following discussions, the term “earnings” is defined as net income or segment income before the cumulative effect of changes in accounting principles. This section should also be read in conjunction with the discussion of the company’s “Business Environment and Outlook” on pages FS-2 through FS-4.

U.S. Upstream – Exploration and Production


Millions of dollars	2004			2003			2002

Income From Continuing Operations	$	3,868		$	3,160		$	1,703
Income From Discontinued Operations		70			23			14
Cumulative Effect of Accounting Change		–			(350	)		–

Segment Income*	$	3,938		$	2,833		$	1,717

*Includes Special-Item Gains (Charges):

Asset Dispositions
Continuing Operations	$	316		$	77		$	–
Discontinued Operations		50			–			–
Litigation Provisions		(55	)		–			–
Asset Impairments/Write-offs		–			(103	)		(183	)
Restructuring and Reorganizations		–			(38	)		–
Environmental Remediation Provisions		–			–			(31	)

Total	$	311		$	(64	)	$	(214	)

FS-6

Income from continuing operations in 2004 of nearly $3.9 billion was about $700 million higher than in 2003. Nearly $400 million of the increase represented the difference in the effect on earnings in the respective periods from special items, which are discussed below. The remaining $300 million improvement was composed of about a $1 billion benefit from higher crude oil and natural gas prices that was largely offset by the effects of lower production.

Income from continuing operations in 2003 was about $3.2 billion, up approximately $1.5 billion from 2002. The benefit of higher prices between periods was about $1.7 billion and was partially offset by the effect of lower production.

The company’s average liquids realization in 2004 was $34.12 per barrel, compared with $26.66 in 2003 and $21.34 in 2002. The average natural gas realization was $5.51 per thousand cubic feet in 2004, compared with $5.01 and $2.89 in 2003 and 2002, respectively.

Net oil-equivalent production averaged 817,000 barrels per day in 2004, down 12 percent from 2003 and 19 percent from 2002. The lower production in 2004 included the effects of about 30,000 barrels per day associated with property sales and 21,000 barrels per day of production shut in as a result of damages to facilities from Hurricane Ivan in the third quarter. Adjusting for the effects of property sales and storms in all periods presented, oil-equivalent production in 2004 declined about 7 percent from 2003 and 14 percent from 2002, mainly as a result of normal field declines that do not typically reverse.

The net liquids component of oil-equivalent production for 2004 averaged 505,000 barrels per day, a decline of 10 percent from 2003 and 16 percent from 2002. Excluding the effects of property sales and storms, net liquids production in 2004 declined 5 percent and 11 percent from 2003 and 2002, respectively.

Net natural gas production averaged 1.9 billion cubic feet per day in 2004, 16 percent lower than 2003 and 22 percent lower than 2002. Adjusting for the effects of property sales and storms, 2004 net natural gas production declined 10 percent in 2003 and 17 percent in 2002.

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

(BAR CHART)

Segment income in 2004 included special gains of $366 million from property sales, partially offset by special charges of $55 million resulting from an adverse litigation matter. Net special charges of $64 million in 2003 were composed of charges of $103 million for asset impairments, associated mainly with the write-down of assets in anticipation of sale; charges of $38 million for restructuring and reorganization, mainly for employee severance costs; and gains of $77 million from property sales. Special charges in 2002 totaled $214 million, which included $183 million for the impairment of a number of fields caused by the write-down of proved reserves and $31 million for costs of environmental remediation.

International Upstream – Exploration and Production


Millions of dollars	2004			2003			2002

Income From Continuing Operations¹	$	5,622		$	3,199		$	2,823
Income From Discontinued Operations		224			21			16
Cumulative Effect of Accounting Change		–			145			–

Segment Income²	$	5,846		$	3,365		$	2,839

¹Includes Foreign Currency Effects:	$	(129	)	$	(319	)	$	90
² Includes Special-Item Gains (Charges):
Asset Dispositions
Continuing Operations	$	644		$	32		$	–
Discontinued Operations		207			–			–
Asset Impairments/Write-offs		–			(30	)		(100	)
Restructuring and Reorganizations		–			(22	)		–
Tax Adjustments		–			118			(37	)

Total	$	851		$	98		$	(137	)

Income from continuing operations of $5.6 billion in 2004 increased about $2.4 billion from 2003. Approximately $1.1 billion of the increase was associated with higher prices for crude oil and natural gas. Approximately $750 million of the increase was the result of the effects of special items in each period, which are discussed below. Another $400 million resulted from lower income-tax expense between periods, including a benefit of about $200 million in 2004 as a result of changes in income tax laws. Otherwise, the benefit of about $200 million in lower foreign currency losses was largely offset by higher transportation costs.

Income from continuing operations of $3.2 billion in 2003 was nearly $400 million higher than in 2002. Higher crude oil and natural gas prices accounted for an increase of about $900 million, which was partially offset by $400 million from the effect of foreign currency changes and about $100 million of higher income tax-expense.

Net oil-equivalent production of 1.7 million barrels per day in 2004 – including other produced volumes of 140,000 net barrels per day from oil sands and production under an operating service agreement – declined about 1 percent from 2003 and 2 percent from 2002. Excluding the lower production associated with property sales and reduced volumes associated with cost-recovery provisions of certain production-sharing agreements, 2004 net oil-equivalent production increased nearly 3 percent from 2003 and 1 percent from 2002 – primarily from higher oil-equivalent production in Chad, Kazakhstan and Venezuela.

The net liquids component of oil-equivalent production, including volumes produced from oil sands and under an operating service agreement, declined about 1 percent from the production level in 2003 and about 3 percent from 2002. Excluding the effects of property sales and lower cost-recovery volumes under certain production-sharing agreements, 2004 net liquids

FS-7


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

production increased about 1 percent from 2003 and decreased about 1 percent from 2002.

The net natural gas component of oil-equivalent production was up 1 percent from 2003 and 6 percent from 2002. During 2004, production increases in Angola, Kazakhstan, Denmark and Australia were partially offset by declines associated with asset sales. In 2003, areas with production increases included Australia, Kazakhstan, the Philippines and the United Kingdom.

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

Special-item gains in 2004 included $585 million from the sale of producing properties in western Canada and $266 million from the sale of other nonstrategic assets, including the company’s operations in the Democratic Republic of the Congo and a Canadian natural-gas processing business. In 2003, net special gains of $98 million included benefits of $150 million related to income taxes and property sales, partially offset by asset impairments in advance of sale and charges for employee termination costs. In 2002, special charges of $137 million included $100 million for asset impairments resulting from the write-down of proved reserves for fields in Africa and Canada.

U.S. Downstream – Refining, Marketing and Transportation


Millions of dollars	2004		2003			2002

Segment Income (Loss)*	$	1,261	$	482		$	(398	)

*Includes Special-Item Gains (Charges):
Asset Dispositions	$	–	$	37		$	–
Asset Impairments/Write-offs		–		–			(66	)
Environmental Remediation Provisions		–		(132	)		(92	)
Restructuring and Reorganizations		–		(28	)		–
Litigation Provisions		–		–			(57	)

Total	$	–	$	(123	)	$	(215	)

(BAR CHART)

The earnings improvement in 2004 from both 2003 and 2002 was associated mainly with higher margins for refined products. Margins in 2004 were the highest in recent years. Margins in 2002 were very depressed, and at one point hovered near their 12-year lows.

Sales volumes for refined products of approximately 1.5 million barrels per day in 2004 increased about 5 percent from 2003. The increase between periods was primarily from higher sales of gasoline, diesel fuel and fuel oil. Branded gasoline sales volumes of 567,000 barrels per day increased

2 percent from 2003. The sales improvement partially reflected the reintroduction of the Texaco brand in the Southeast. In 2003, sales volumes for refined products declined about 10 percent from the prior year. Industry demand in 2003 was weaker for branded gasoline, diesel and jet fuels and sales were lower under certain supply contracts.

Refer to the “Selected Operating Data” table on page FS-10 for the three-year comparative refined-product sales volumes in the United States.

In 2003, net special charges of $123 million included $160 million for environmental remediation and employee severance costs associated with the global downstream restructuring and reorganization. These charges were partially offset by gains on asset sales. In 2002, special charges of $215 million included amounts for environmental remediation, the write-down of the El Paso refinery in advance of sale and a litigation matter.

(BAR CHART)

International Downstream –
Refining, Marketing and Transportation


Millions of dollars	2004		2003			2002

Segment Income^1,2	$	1,989	$	685		$	31

¹Includes Foreign Currency Effects:	$	7	$	(141	)	$	(176	)
² Includes Special-Item Gains (Charges):
Asset Dispositions	$	–	$	(24	)	$	–
Asset Impairments/Write-offs		–		(123	)		(136	)
Restructuring and Reorganizations		–		(42	)		–

Total	$	–	$	(189	)	$	(136	)

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

Earnings of nearly $2 billion in 2004 improved significantly from 2003 and 2002, mainly the result of higher average margins for refined products for both company and affiliate operations and higher earnings from international shipping operations. Margins in

FS-8

2004 were the highest in recent years. Earnings in 2004 also included a benefit of $40 million related to changes in income tax laws.

Total international refined products sales volumes were 2.4 million barrels per day in 2004, more than 4 percent higher than 2.3 million in 2003 and about 10 percent higher than 2.2 million in 2002. Weak economic conditions dampened industry demand in 2002. Refer to the “Selected Operating Data” table on page FS-10 for the three-year comparative refined-product sales volumes in the international areas.

Special charges of $189 million in 2003 included the write-down of the Batangas Refinery in the Philippines in advance of its conversion to a product terminal facility, employee severance costs associated with the global downstream restructuring and reorganization, the impairment of certain assets in anticipation of their sale, and the company’s share of losses from an asset sale and asset impairment by an equity affiliate. The special charge in 2002 was for a write-down of the company’s investment in its publicly traded Caltex Australia Limited affiliate to its estimated fair value.

Chemicals


Millions of dollars	2004			2003		2002

Segment Income*	$	314		$	69	$	86

*Includes Foreign Currency Effects:	$	(3	)	$	13	$	3

(BAR CHART)

The chemicals segment includes the company’s Oronite division and the company’s 50 percent share of its equity investment in Chevron Phillips Chemical Company LLC (CPChem). In 2004, results for the company’s Oronite subsidiary improved on higher sales volumes. Earnings in 2004 for CPChem increased as the result of increased chemical commodity margins and sales volumes and higher equity affiliate income. Protracted weak demand for commodity chemicals and industry oversupply conditions suppressed earnings for this segment in 2003 and 2002.

All Other


Millions of dollars	2004			2003			2002

Charges Before Cumulative Effect of Changes in Accounting Principles	$	(20	)	$	(213	)	$	(3,143	)
Cumulative Effect of Accounting Changes		–			9			–

Net Charges^1,2	$	(20	)	$	(204	)	$	(3,143	)

¹ Includes Foreign Currency Effects	$	44		$	43		$	40
² Includes Special-Item Gains (Charges):

Dynegy-Related	$	–		$	325		$	(2,306	)
Asset Impairments/Write-offs		–			(84	)		–
Restructuring and Reorganizations		–			(16	)		–
Tax Adjustments		–			–			97
Environmental Remediation Provisions		–			–			(37	)
Merger-Related Expenses		–			–			(386	)

Total	$	–		$	225		$	(2,632	)

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

The improvement between 2003 and 2004 was primarily associated with the company’s investment in Dynegy, including gains from the redemption of certain Dynegy securities, higher interest income, lower interest expense, and favorable corporate-level tax adjustments. The net change between 2002 and 2003 was largely attributable to the differences in the effect of net special charges. The 2003 period also included lower interest expense and other corporate charges compared with 2002.

Net special gains in 2003 included a benefit of $365 million from the exchange of the company’s investment in Dynegy preferred stock for cash and other Dynegy securities. This benefit was partially offset by charges for asset write-downs of $84 million, primarily in the gasification business, which was later sold; $40 million for the company’s share of an asset impairment by Dynegy; and employee severance costs of $16 million.

Special charges in 2002 included $2.3 billion related to Dynegy, composed of $1.6 billion for the write-down of the company’s investment in Dynegy common and preferred stock to its estimated fair value and $680 million for the company’s share of Dynegy’s own special items for asset write-downs and revaluations, and a loss on an asset sale. Refer also to page FS-11 for “Information Relating to the Company’s Investment in Dynegy.”

CONSOLIDATED STATEMENT OF INCOME

Comparative amounts for certain income statement categories are shown in the following table. For each category, the amounts associated with special items in the comparative periods are also indicated to assist in the explanation of the period-to-period changes. Besides the information in this section, separately disclosed on the face of the Consolidated Statement of Income are a gain from the exchange of Dynegy securities, merger-related expenses, write-down of investments in Dynegy and the cumulative effect of changes in accounting principles. These matters are discussed elsewhere in MD&A and in Note 14 to the Consolidated Financial Statements on page FS-39.


Millions of dollars	2004		2003			2002

Income (loss) from equity affiliates	$	2,582	$	1,029		$	(25	)

Memo: Special gains (charges), before tax		–		179			(829	)

Other income	$	1,853	$	308		$	222

Memo: Special gains, before tax		1,281		217			–

Operating expenses	$	9,832	$	8,500		$	7,795

Memo: Special charges, before tax		85		329			259

Selling, general and administrative expenses	$	4,557	$	4,440		$	4,155

Memo: Special charges, before tax		–		146			180

Depreciation, depletion and amortization	$	4,935	$	5,326		$	5,169

Memo: Special charges, before tax		–		286			298

Interest and debt expense	$	406	$	474		$	565

Memo: Special charges, before tax		–		–			–

Taxes other than on income	$	19,818	$	17,901		$	16,682

Memo: Special charges, before tax		–		–			–

Income tax expense	$	7,517	$	5,294		$	2,998

Memo: Special charges (benefits)		291		(312	)		(604	)

FS-9


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

Explanations follow for variations between years for the amounts in the table above – after consideration of the effects of special gains and charges – as well as for other income statement categories. Refer to the preceding segment discussions in this section for information relating to special gains and charges.

Sales and other operating revenues were $151 billion in 2004, compared with $120 billion in 2003 and $98 billion in 2002. Revenues increased in 2004 and 2003 primarily from higher prices for crude oil, natural gas and refined products worldwide.

Income (loss) from equity affiliates increased in 2004 and 2003, as earnings improved for a number of affiliates, including downstream affiliates in the Asia-Pacific area, Tengizchevroil, CPChem, Dynegy and the Caspian Pipeline Consortium.

Other income in 2004 included net gains of $1.6 billion, primarily from upstream property sales, compared with gains of $286 million and $94 million in 2003 and 2002, respectively. Interest income increased to $199 million in 2004, compared with about $120 million in 2003 and 2002, as a result of higher balances of cash and marketable securities. Foreign currency losses were $60 million, $199 million and $5 million in 2004, 2003 and 2002, respectively.

Purchased crude oil and products were $94 billion in 2004, an increase of 32 percent from 2003, due mainly to higher prices and increased purchases of crude oil and products. Crude oil and product purchases increased about 25 percent in 2003, primarily due to significantly higher prices for crude oil, natural gas and refined products.

Operating, selling, general and administrative expenses of $14 billion increased from $13 billion in 2003. The increases in 2004 included costs for chartering of crude oil tankers and other transportation expenses. During 2003, operating, selling, general and administrative expenses increased nearly $1 billion, primarily from higher freight rates for international shipping operations and higher costs associated with employee pension plans and other employee-benefit expenses.

Exploration expenses were $697 million in 2004, $570 million in 2003 and $591 million in 2002. In 2004, amounts were higher for international operations, primarily for seismic costs and expenses associated with evaluating the feasibility of different project alternatives.

Depreciation, depletion and amortization expenses did not change materially between years after consideration of the effects of special-item charges.

Interest and debt expense was $406 million in 2004, compared with $474 million in 2003 and $565 million in 2002. The lower amount in 2004 reflected lower average debt balances. The decline between 2003 and 2002 reflected lower average interest rates on commercial paper and other variable-rate debt and lower average debt levels.

Taxes other than on income were $19.8 billion, $17.9 billion and $16.7 billion in 2004, 2003 and 2002, respectively. The increase in 2004 and 2003 primarily reflected the weakening U.S. dollar on foreign currency-denominated duties in the company’s European downstream operations.

Income tax expense corresponded to effective tax rates of 37 percent in 2004, 43 percent in 2003 and 45 percent in 2002 after taking into account the effect of net special items. Refer also to Note 17 on page FS-42 to the Consolidated Financial Statements.

Merger-related expenses were $576 million in 2002. No merger-related expenses were reported in 2004 or 2003, reflecting the completion of merger integration activities in 2002.

SELECTED OPERATING DATA^1,2


	2004		2003		2002

U.S. Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD)		505		562		602
Net Natural Gas Production (MMCFPD)³		1,873		2,228		2,405
Net Oil-Equivalent Production (MBOEPD)		817		933		1,003
Natural Gas Sales (MMCFPD)		4,518		4,304		5,891
Natural Gas Liquids Sales (MBPD)		177		194		241
Revenues From Net Production
Liquids ($/Bbl)	$	34.12	$	26.66	$	21.34
Natural Gas ($/MCF)	$	5.51	$	5.01	$	2.89

International Upstream
Net Crude and Natural Gas Liquids Production (MBPD)		1,205		1,246		1,295
Net Natural Gas Production (MMCFPD)³		2,085		2,064		1,971
Net Oil-Equivalent Production (MBOEPD)⁴		1,692		1,704		1,720
Natural Gas Sales (MMCFPD)		1,885		1,951		3,131
Natural Gas Liquids Sales (MBPD)		105		107		131
Revenues From Liftings
Liquids ($/Bbl)	$	34.17	$	26.79	$	23.06
Natural Gas ($/MCF)	$	2.68	$	2.64	$	2.14
Net Oil-Equivalent Production Including Other Produced Volumes (MBPD)^3,4
U.S.		817		933		1,003
International		1,692		1,704		1,720

Total		2,509		2,637		2,723

U.S. Downstream – Refining, Marketing and Transportation
Gasoline Sales (MBPD)		701		669		680
Other Refined Products Sales (MBPD)		805		767		920

Total⁵		1,506		1,436		1,600
Refinery Input (MBPD)⁶		914		951		979

International Downstream – Refining Marketing and Transportation
Gasoline Sales (MBPD)		717		643		620
Other Refined Products Sales (MBPD)		1,685		1,659		1,555

Total⁷		2,402		2,302		2,175
Refinery Input (MBPD)		1,044		1,040		1,100

¹ Includes equity in affiliates.
² MBPD = Thousands of barrels per day; MMCFPD = Millions of cubic feet per day; MBOEPD = Thousands of barrels of oil equivalents per day; Bbl = Barrel; MCF = Thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of gas = 1 barrel of oil.
³ Includes natural gas consumed on lease:
United States		50		65		64
International		293		268		256
⁴ Other produced volumes includes:
Athabasca Oil Sands – Net		27		15		–
Boscan Operating Service Agreement		113		99		97

		140		114		97
⁵ Includes volume for buy/sell contracts:		84		90		101
⁶ The company sold its interest in the El Paso Refinery in August 2003.
⁷ Includes volume for buy/sell contracts:		96		104		96

FS-10

INFORMATION RELATED TO INVESTMENT IN DYNEGY INC.

At year-end 2004, ChevronTexaco owned an approximate 25 percent equity interest in the common stock of Dynegy – an energy provider engaged in power generation, gathering and processing of natural gas, and the fractionation, storage, transportation and marketing of natural gas liquids. The company also held an investment in Dynegy preferred stock.

Investment in Dynegy Common Stock At December 31, 2004, the carrying value of the company’s investment in Dynegy common stock was approximately $150 million. This amount was about $365 million below the company’s proportionate interest in Dynegy’s underlying net assets. This difference is primarily the result of write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value that were deemed to be other than temporary. The difference has been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors giving rise to the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly when appropriate to recognize a portion of the difference between these allocated values and Dynegy’s historical book values. The market value of the company’s investment in Dynegy’s common stock at December 31, 2004, was approximately $450 million.

Investments in Dynegy Notes and Preferred Stock At the beginning of 2004, the company held $223 million face value of Dynegy Junior Unsecured Subordinated Notes due 2016 and $400 million face value of Dynegy Series C Convertible Preferred Stock with a stated maturity of 2033.

The Junior Notes were redeemed at face value during 2004, and gains of $54 million were recorded for the difference between the face amounts and the carrying values at the time of redemption. The face value of the company’s investment in the Series C preferred stock at December 31, 2004, was $400 million. The stock is recorded at its fair value, which was estimated to be $370 million at December 31, 2004. Future temporary changes in the estimated fair value of the preferred stock will be reported in “Other comprehensive income.” However, if any future decline in fair value is deemed to be other than temporary, a charge against income in the period would be recorded. Dividends received from the preferred stock are recognized in income each period.

LIQUIDITY AND CAPITAL RESOURCES

Cash, Cash Equivalents and Marketable Securities Total balances were $10.7 billion and $5.3 billion at December 31, 2004 and 2003, respectively. Cash provided by operating activities in 2004 was $14.7 billion, compared with $12.3 billion in 2003 and $9.9 billion in 2002. These amounts were net of contributions to employee pension plans of $1.6 billion, $1.4 billion and $246 million in 2004, 2003 and 2002, respectively. The 2004 increase in cash provided by operating activities mainly reflected higher earnings in the worldwide upstream and downstream businesses. Cash provided by investing activities included proceeds from asset sales of $3.7 billion in 2004, $1.1 billion in 2003 and $2.3 billion in 2002.

Cash provided by operating activities and asset sales during 2004 was sufficient to fund the company’s capital and exploratory program, pay $3.2 billion of dividends to stockholders, reduce total debt by $1.3 billion, repurchase $2.1 billion of common stock, and increase the balance of cash, cash equivalents and marketable securities by $5.5 billion.

Dividends Payments of approximately $3.2 billion in 2004 and $3 billion in 2003 and 2002 were made for dividends. In

September 2004, the company increased its quarterly common stock dividend by 10 percent to 40 cents per share, on a post-stock split basis.

Debt, Capital Lease and Minority Interest Obligations Total debt and capital lease balances were $11.3 billion at December 31, 2004, down from $12.6 billion at year-end 2003. The company also had minority interest obligations of $172 million, down from $268 million at December 31, 2003.

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 $5.6 billion at December 31, 2004, down from $6.0 billion at December 31, 2003. Of these amounts, $4.7 billion and $4.3 billion were reclassified to long-term at the end of each period, respectively. At year-end 2004, settlement of these obligations was not expected to require the use of working capital in 2005, as the company had 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 2004, ChevronTexaco had $4.7 billion in committed credit facilities with various major banks, which permitted the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowings and also can be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at December 31, 2004. In addition, the company had three existing effective “shelf” registrations on file with the Securities and Exchange Commission (SEC) that together would permit additional registered debt offerings up to an aggregate of $3.8 billion of debt securities.

In 2004, repayments of long-term debt at maturity included $500 million of 6.625 percent ChevronTexaco Corporation bonds, an aggregate $265 million of various Philippine debt and $240 million of ChevronTexaco Corporation 8.11 percent notes.

(BAR CHARTS)

FS-11


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

In the third quarter 2004, $300 million of 6 percent Texaco Capital Inc., due June 2005, were also retired.

Texaco Capital LLC, a wholly owned finance subsidiary, issued Deferred Preferred Shares, Series C (Series C), in December 1995. In February 2005, the company redeemed the Series C and accumulated dividends at a cost of approximately $140 million.

In January 2005, the company contributed $98 million to permit the ESOP to make a $144 million debt service payment, which included a principal payment of $113 million.

In the second quarter 2004, ChevronTexaco entered into $1 billion of interest rate fixed-to-floating swap transactions. Under the terms of the swap agreements, of which $250 million and $750 million terminate in September 2007 and February 2008, respectively, the net cash settlement will be based on the difference between fixed-rate and floating-rate interest amounts.

ChevronTexaco’s senior debt is rated AA by Standard and Poor’s Corporation and Aa2 by Moody’s Investor Service, except for senior debt of Texaco Capital Inc., which is 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. Further reductions from debt balances at December 31, 2004, are dependent upon many factors, including management’s continuous assessment of debt as an appropriate component of the company’s overall capital structure. 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, the company believes that it has the flexibility to increase borrowings or modify capital-spending plans or both to continue paying the common stock dividend and maintain the company’s high-quality debt ratings.

Tengizchevroil Funding As part of the funding of the expansion of Tengizchevroil’s (TCO) production facilities, in the fourth quarter 2004 ChevronTexaco purchased from TCO $2.2 billion of 6.124 percent Series B Notes (Series B), due 2014. Interest on the notes is payable semiannually, and principal is to be repaid semi-annually in equal installments beginning in February 2008.

Immediately following the purchase of the Series B, ChevronTexaco received from TCO approximately $1.8 billion, representing a repayment of subordinated loans from the company, interest

and dividends. The $2.2 billion investment in the Series B Notes, which the company intends to hold until maturity, and the $1.8 billion distribution were recorded on the Consolidated Balance Sheet to “Investments and Advances.”

Common Stock Repurchase Program The company announced a stock repurchase program on March 31, 2004. Acquisitions of up to $5 billion may be made from time to time at prevailing prices, as permitted by securities laws and other legal requirements, and subject to market conditions and other factors. The program is for a period of up to three years and may be discontinued at any time. The company purchased 42,324,000 shares in the open market for $2.1 billion through December 2004. Purchases through February 2005 increased the total shares acquired to 47,969,000 for $2.4 billion.

Capital and Exploratory Expenditures Total reported expenditures for 2004 were $8.3 billion, including $1.56 billion for the company’s share of affiliates’ expenditures, which did not require cash outlays by the company. In 2003 and 2002, expenditures were $7.4 billion and $9.3 billion, respectively, including the company’s share of affiliates’ expenditures of $1.1 billion and $1.4 billion in the corresponding periods. Of the total 2004 reported expenditures, $6.3 billion, or 76 percent, was for upstream activities, compared with 77 percent in 2003 and 68 percent in 2002. International upstream accounted for 71 percent of the worldwide upstream total in 2004 and 2003 and 70 percent in 2002, reflecting the company’s continuing focus on international exploration and production activities.

Expenditures in 2004 increased 13 percent compared with 2003, primarily driven by higher upstream expenditures. Downstream spending increased 21 percent from 2003. Expenditures were higher in 2002 than in 2003, due in part to large lease acquisitions in the North Sea and the Gulf of Mexico, spending for the Athabasca Oil Sands Project in western Canada, and additional common stock investments in Dynegy.

Including its share of spending by affiliates, the company estimates 2005 capital and exploratory expenditures at $10 billion, which is about 20 percent higher than 2004. About $7.4 billion, or 74 percent of the total, is targeted for exploration and production activities, with $4.9 billion of that amount targeted for outside the United States. The upstream spending is targeted for the most promising exploratory prospects in the deepwater Gulf of Mexico and West Africa and major development projects in Angola, Nigeria, Kazakhstan and the deepwater Gulf of Mexico. Included in the upstream expenditures is about $400 million to develop the company’s international natural gas resource base.

Worldwide downstream spending in 2005 is estimated at $1.9 billion, with about $1.5 billion for refining and marketing

Capital and Exploratory Expenditures


	2004						2003						2002
Millions of dollars	U.S.		Int’l.		Total		U.S.		Int’l.		Total		U.S.			Int’l.			Total

Exploration and Production	$	1,820	$	4,501	$	6,321	$	1,641	$	4,034	$	5,675	$	1,888		$	4,395		$	6,283
Refining, Marketing and Transportation		497		832		1,329		403		697		1,100		750			882			1,632
Chemicals		123		27		150		173		24		197		272			37			309
All Other		512		3		515		371		20		391		855	*		176	*		1,031

Total	$	2,952	$	5,363	$	8,315	$	2,588	$	4,775	$	7,363	$	3,765		$	5,490		$	9,255

Total, Excluding Equity in Affiliates	$	2,729	$	4,024	$	6,753	$	2,306	$	3,920	$	6,226	$	3,312		$	4,590		$	7,902

*2002 conformed to 2004 presentation.

FS-12

(BAR CHARTS)

and $400 million for supply and transportation projects, including pipelines to support expanded upstream production.

Investments in chemicals businesses in 2005 are budgeted at $200 million. Estimates for energy technology, information technology and facilities, and power-related businesses total approximately $500 million.

Pension Obligations In 2004, the company’s pension plan contributions totaled $1.6 billion (approximately $1.3 billion to the U.S. plans). In 2005, the company expects contributions to be approximately $400 million. Actual amounts are dependent upon investment results, changes in pension obligations, regulatory environments and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations. Refer also to the discussion of pension accounting in “Critical Accounting Estimates and Assumptions” beginning on page FS-18.

FINANCIAL RATIOS

Current Ratio – current assets divided by current liabilities. The current ratio is adversely affected by the fact that ChevronTexaco’s inventories are valued on a Last-In, First-Out (LIFO) basis. At year-end 2004, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $3.0 billion.

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

Debt Ratio – total debt as a percentage of total debt plus equity. The decrease between the comparable periods was due to lower average debt levels and higher retained earnings.

Financial Ratios


				At December 31
	2004			2003			2002

Current Ratio		1.5			1.2			0.9
Interest Coverage Ratio		47.6			24.3			7.6
Total Debt/Total Debt-Plus-Equity		19.9	%		25.8	%		34.0	%

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

Direct or Indirect Guarantees*


Millions of dollars	Commitment Expiration by Period
					2006-				After
	Total		2005		2008		2009		2009

Guarantees of Non-consolidated Affiliates or Joint Venture Obligations	$	963	$	515	$	210	$	135	$	103
Guarantees of Obligations of Third Parties		130		70		16		4		40
Guarantees of Equilon Debt and Leases		215		18		61		18		118


*	The amounts exclude indemnifications of contingencies associated with the sale of the company’s interest in Equilon and Motiva in 2002, as discussed in the “Indemnifications” section on page FS-14.

At December 31, 2004, the company and its subsidiaries provided guarantees either directly or indirectly, of $963 million for notes and other contractual obligations of affiliated companies and $130 million for third parties as described by major category below. There are no amounts being carried as liabilities for the company’s obligations under these guarantees.

Of the $963 million in guarantees provided to affiliates, $774 million 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 90 percent of the amounts guaranteed will expire by 2009, with the remaining guarantees expiring by the end of 2015. Under the terms of the guarantees, the company would be required to fulfill the guarantee should an affiliate be in default of its loan terms, generally for the full amounts disclosed. There are no recourse provisions, and no assets are held as collateral for these guarantees. The $189 million balance of the $963 million represents 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 affiliate does not perform under the agreements. There are no recourse provisions to third parties, and no assets are held as collateral for these pricing guarantees.

Guarantees of $130 million have been provided to third parties, including guarantees of approximately $40 million of construction loans to host governments in the company’s international upstream operations. The remaining guarantees of $90 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. About 70 percent of the total amounts guaranteed will expire in 2009, with the remainder expiring after 2009. 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 $70 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.

At December 31, 2004, ChevronTexaco also had outstanding guarantees for approximately $215 million of Equilon debt and leases. Following the February 2002 disposition of its interest in Equilon, the company received an indemnification from Shell

FS-13


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

Oil Company (Shell) for any claims arising from the guarantees. The company has not recorded a liability for these guarantees. Approximately 45 percent of the amounts guaranteed will expire within the 2005 through 2009 period, with the guarantees of the remaining amounts expiring by 2019.

Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover certain contingent liabilities, including those associated with the Unocal patent litigation. The company would be required to perform should the indemnified liabilities become actual losses. Should that occur, the company could be required to make future payments up to $300 million. Through the end of 2004, the company paid approximately $28 million under these contingencies and had agreed to pay approximately $10 million additional under an award of arbitration, subject to minor adjustments yet to be resolved. The company may receive additional requests for indemnification payments in the future.

The company has also provided indemnities relating to contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the periods of Texaco’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 2001. Claims relating to Equilon indemnities must be asserted either as early as February 2007, or no later than February 2009, and claims relating to Motiva must be asserted no later than February 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 company posts no assets as collateral and has made no payments under the indemnities.

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

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, 2004, approximately $1.2 billion, representing about 10 percent of ChevronTexaco’s total current accounts receivable balance, were securitized. ChevronTexaco’s total estimated financial exposure under these securitizations at December 31, 2004, was approximately $50 million. 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 believes that it would have no loss exposure connected with third-party investments in these securitizations.

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 approximate amounts of required payments under these various commitments are 2005 – $1.6 billion; 2006 – $1.7 billion; 2007 – $1.6 billion; 2008 – $1.5 billion; 2009 – $1.5 billion; 2010 and after – $2.3 billion. Total payments under the agreements were approximately $1.6 billion in 2004, $1.4 billion in 2003 and $1.2 billion in 2002. 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: 2005 – $1.2 billion; 2006 – $1.2 billion; 2007 – $1.3 billion; 2008 – $1.3 billion; and 2009 – $1.3 billion. Additionally, in 2004 the company entered into a 20-year agreement to acquire regasification capacity at the Sabine Pass LNG terminal. Payments of $1.2 billion over the 20-year period are expected to commence in 2010.

Minority Interests The company has commitments of approximately $172 million related to minority interests in subsidiary companies.

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

Contractual Obligations


Millions of dollars	Payments Due by Period
					2006 -				After
	Total		2005		2008		2009		2009

On-Balance-Sheet:
Short-Term Debt	$	816	$	816	$	–	$	–	$	–
Long-Term Debt^{1, 2}		10,217		–		8,123		455		1,639
Noncancelable Capital Lease Obligations		239		–		110		29		100
Interest Expense		4,830		465		1,120		270		2,975
Off-Balance-Sheet:
Noncancelable Operating Lease Obligations		2,232		390		857		236		749
Unconditional Purchase Obligations		1,000		300		600		100		–
Through-Put and Take-or-Pay Agreements		9,400		1,350		4,250		1,450		2,350


¹	$4.7 billion of short-term debt that the company expects to refinance is included in long-term debt. The repayment schedule above reflects the repayment of the entire amount in the 2006 through 2008 period.


²	Includes guarantees of $360 of LESOP (leveraged employee stock ownership Plan) debt, $127 due in 2005 and $233 due after 2006.

FINANCIAL AND DERIVATIVE INSTRUMENTS

Commodity Derivative Instruments ChevronTexaco is exposed to market risks related to the volatility of crude oil, refined products, electricity, natural gas and refinery feedstock prices. The company uses financial 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 and refined products; feedstock purchases for company refineries; crude oil and refined products inventories; and fixed-price contracts to sell natural gas and natural gas liquids.

FS-14

ChevronTexaco also uses financial derivative commodity instruments for trading purposes, and the results of this activity were not material to the company’s financial position, net income or cash flows in 2004.

The company’s positions are monitored and reported 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 Audit Committee of the company’s Board of Directors.

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

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

Each hypothetical 10 percent increase in the price of natural gas and crude oil would increase the fair value of the natural gas derivative contracts by approximately $40 million and reduce the fair value of the crude oil derivative contracts by about $15 million. The same hypothetical decreases in the prices of these commodities would result in the same opposite effects on the fair values of the contracts.

The hypothetical effect on these 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 balance sheet with resulting gains and losses reflected in income.

The aggregate effect on foreign exchange contracts of a hypothetical 10 percent change to year-end exchange rates would be approximately $50 million.

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 relating 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 2004, four new swaps were initiated to hedge a portion of the company’s fixed-rate debt. At year-end 2004, the weighted average maturity of “receive fixed” interest rate swaps was approximately three years. There were no “receive floating” swaps outstanding at year end.

A hypothetical increase of 10 basis points in market-fixed interest rates would reduce the fair value of the “receive fixed” swaps by approximately $4 million.

For the financial and derivative instruments discussed above, there was not a material change in market risk from that presented in 2003.

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

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 and offtake agreements. Internationally, there are long-term purchase agreements in place with the company’s refining affiliate in Thailand. Refer to page FS-14 for further discussion. Management believes the foregoing agreements and others have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.

LITIGATION AND OTHER CONTINGENCIES

MTBE The company and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive.

The company is a party to more than 70 lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners, related to the use of MTBE in certain oxygenated gasolines and the alleged seepage of MTBE into groundwater. Resolution of these actions may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future.

The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company does not use MTBE in the manufacture of gasoline in the United States and there are no detectable levels of MTBE in that gasoline.

Environmental The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, oil fields, service stations, terminals, and land development areas, whether operating, closed or sold. The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for federal Superfund sites and analogous sites under state laws. In 2004, the company recorded additional provisions for estimated remediation costs primarily at refined products marketing sites and various operating, closed or divested facilities in the United States.


Millions of dollars	2004			2003			2002

Balance at January 1	$	1,149		$	1,090		$	1,160
Net Additions		155			296			229
Expenditures		(257	)		(237	)		(299	)

Balance at December 31	$	1,047		$	1,149		$	1,090

The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state or local regulations. No single remediation site at year-end 2004 had a recorded liability that was material to the company’s financial position, results of operations or liquidity.

FS-15


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

As of December 31, 2004, ChevronTexaco was involved with the remediation activities of 210 sites at which it had been identified as a potentially responsible party or otherwise by the U.S. Environmental

(BAR CHART)

Protection Agency (EPA) or other regulatory agencies under the provisions of the federal Superfund law or analogous state laws. The company’s remediation reserve for these sites at year-end 2004 was $107 million. The federal Superfund law and analogous state laws provide for joint and several liability for all responsible parties. Any future actions by the EPA or other regulatory agencies to require 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.

Of the remaining year-end 2004 environmental reserves balance of $940 million, $712 million related to more than 2,000 sites for the company’s U.S. downstream operations, including refineries and other plants, marketing locations

(i.e., service stations and terminals), and pipelines. The remaining $228 million was associated with various sites in the international downstream ($111 million), upstream ($69 million) and chemicals ($48 million). Liabilities at all sites, whether operating, closed or divested, were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both. These and other activities include one or more of the following: site assessment; soil excavation; offsite disposal of contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid and vapor from soil; groundwater extraction and treatment; and monitoring of the natural attenuation of the contaminants.

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

Prior to January 1, 2003, additional reserves for dismantlement, abandonment and restoration of its worldwide oil and gas and coal properties at the end of their productive lives, which

included costs related to environmental issues, were recognized on a unit-of-production basis as accumulated depreciation, depletion and amortization. Effective January 1, 2003, the company implemented FAS 143, “Accounting for Asset Retirement Obligations.” Under FAS 143, the fair value of a liability for an asset retirement obligation is recorded when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. The liability balance for asset retirement obligations at year-end 2004 was $2.9 billion. Refer also to Note 25 on page FS-53 related to FAS 143.

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

Refer to “Environmental Matters” on page FS-18 for additional information related to environmental matters.

Income Taxes The company estimates its income tax expense and liabilities quarterly. These liabilities generally are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been estimated. The U.S. federal income tax liabilities have been settled through 1996 for ChevronTexaco (formerly Chevron), 1997 for ChevronTexaco Global Energy Inc. (formerly Caltex), and 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.

Global Operations ChevronTexaco and its affiliates have operations in approximately 180 countries. Areas in which the company and its affiliates have significant operations include the United States, Canada, Australia, the United Kingdom, Norway, Denmark, France, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, Republic of Congo, Angola, Nigeria, Chad, South Africa, Indonesia, the Philippines, Singapore, China, Thailand, Venezuela, Argentina, Brazil, Colombia, Trinidad and Tobago, and South Korea. The company’s Caspian Pipeline Consortium (CPC) affiliate operates in Russia and Kazakhstan. The company’s Tengizchevroil affiliate operates in Kazakhstan. The company’s CPChem affiliate manufactures and markets a wide range of petrochemicals on a worldwide basis, with manufacturing facilities in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar, Mexico and Belgium.

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

FS-16

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, acts of violence 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 crude oil and natural gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude oil and natural gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermina-tion 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 remains 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 estimated at about $50 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

Suspended Wells The company suspends the costs of exploratory wells pending a final determination of the commercial potential of the related crude oil and natural gas fields. The ultimate disposition of these well costs is dependent on the results of future drilling activity or development decisions or both. If the company decides not to continue development, the costs of these wells are expensed. At December 31, 2004, the company had $671 million of suspended exploratory wells included in properties, plant and equipment, an increase of $122 million from 2003 and an increase of $193 million from 2002. The balance at year-end 2004 primarily reflects drilling activities in the United States and Nigeria.

The SEC has issued several comment letters to companies in the oil and gas industry related to the accounting for suspended exploratory wells, particularly for those suspended under certain circumstances for more than one year.

The company’s accounting policy in this regard is to capitalize the cost of exploratory wells pending determination of whether the wells found proved reserves. Costs of wells that find 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 well costs are expensed.

This topic was discussed at the September 2004 meeting of the Emerging Issues Task Force (EITF) as Issue 04-9, “Accounting for Suspended Well Costs” (EITF 04-9). The discussion centered on whether certain circumstances would permit the continued capitalization of the costs for an exploratory well beyond one year in the absence of plans for another exploratory well. The outcome of the September 2004 EITF meeting was agreement

between the EITF and the FASB that the circumstances outlined were inconsistent with the provisions in FASB Statement No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (FAS 19), and an amendment of FAS 19 would be required to formally adopt this view. In February 2005, the FASB issued a proposed FASB Staff Position (FSP) to amend FAS 19. Refer to Note 21 on page FS-45 to the Consolidated Financial Statements for a discussion of this FSP, the SEC’s comment letters and the company’s costs associated with suspended exploratory wells.

The future trend of the company’s exploration expenses can be affected by amounts associated with well write-offs, including wells that had been previously suspended pending determination as to whether the well had found reserves that could be classified as proved. The effect on exploration expenses in future periods for the $671 million of suspended wells at year-end 2004 is uncertain, given the referenced deliberations by the SEC and FASB, as is the effect on the normal project-evaluation and future drilling activities for all of the wells that have been suspended.

Accounting for Buy/Sell Contracts In January and February 2005, the Securities and Exchange Commission (SEC) issued comment letters to ChevronTexaco and other companies in the oil and gas industry requesting disclosure of information related to the accounting for buy/sell contracts. Under a buy/sell contract, a company agrees to buy a specific quantity and quality of a commodity to be delivered at a specific location while simultaneously agreeing to sell a specified quantity and quality of a commodity at a different location to the same counterparty. Physical delivery occurs for each side of the transaction, and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk, and risk of nonperformance by the counterparty. Both parties settle each side of the buy/sell through separate invoicing.

The company routinely has buy/sell contracts, primarily in the United States downstream business, associated with crude oil and refined products. For crude oil, these contracts are used to facilitate the company’s crude oil marketing activity, which includes the purchase and sale of crude oil production, fulfillment of the company’s supply arrangements as to physical delivery location and crude oil specifications, and purchase of crude oil to supply the company’s refining system. For refined products, buy/sell arrangements are used to help fulfill the company’s supply agreements to customer locations and specifications.

The company accounts for buy/sell transactions in the Consolidated Statement of Income the same as any other monetary transaction for which title passes, and the risk and reward of ownership are assumed by the counterparties. At issue with the SEC is whether the industry’s accounting for buy/sell contracts instead should be shown net on the income statement and accounted for under the provisions of Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions” (APB 29).

The topic is under deliberation by the Emerging Issues Task Force (EITF) of the FASB as Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The EITF first discussed this issue in November 2004. Additional research is being performed by the FASB staff, and the topic will be discussed again at a future EITF meeting. While this issue is under deliberation, the SEC staff directed ChevronTexaco and other companies in its January and February 2005 comment letters to disclose on the face of the income statement the amounts asso-

FS-17


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

ciated with buy/sell contracts and to discuss in a footnote to the financial statements the basis for the underlying accounting.

With regard to the latter, the company’s accounting treatment for buy/sell contracts is based on the view that such transactions are monetary in nature. Monetary transactions are outside the scope of APB 29. The company believes its accounting is also supported by the indicators of gross reporting of purchases and sales in paragraph 3 of EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Additionally, FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (FIN 39), prohibits a receivable from being netted against a payable when the receivable is subject to credit risk unless a right of offset exists that is enforceable by law. The company also views netting the separate components of buy/sell contracts in the income statement to be inconsistent with the gross presentation that FIN 39 requires for the resulting receivable and payable on the balance sheet.

The company’s buy/sell transactions are also similar to the “barrel back” example used in other accounting literature, including EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3” (which indicates a company’s decision to show buy/sell-types of transactions gross on the income statement as being a matter of judgment of the relevant facts and circumstances of the company’s activities) and Derivatives Implementation Group (DIG) Issue No. K1, “Miscellaneous: Determining Whether Separate Transactions Should be Viewed as a Unit".

The company further notes that the accounting for buy/sell contracts as separate purchases and sales is in contrast to the accounting for other types of contracts typically described by the industry as exchange contracts, which are considered non-monetary in nature and appropriately shown net on the income statement. Under an exchange contract, for example, one company agrees to exchange refined products in one location for another company’s same quantity of refined products in another location. Upon transfer, the only amounts that may be invoiced are for transportation and quality differentials. Among other things, unlike buy/sell contracts, the obligations of each party to perform under the contract are not independent and the risks and rewards of ownership are not separately transferred.

As shown on the company’s Consolidated Statement of Income, “Sales and other operating revenues” for the three years ending December 31, 2004, included $18,650 million, $14,246 million and $7,963 million, respectively, for buy/sell contracts. These revenue amounts associated with buy/sell contracts represented 12 percent of total “Sales and other operating revenues” in 2004 and 2003 and 8 percent in 2002. The costs associated with these buy/sell revenue amounts are included in “Purchased crude oil and products” on the Consolidated Statement of Income in each period.

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 or remedial work or both to meet current standards. Using definitions and guidelines established by the American Petroleum Institute, ChevronTexaco estimated its worldwide environmental spending in 2004 at approximately $1.1 billion for its consolidated companies. Included in these expenditures were $285 million of environmental capital expenditures and approximately $810 million of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites and the abandonment and restoration of sites.

For 2005, total worldwide environmental capital expenditures are estimated at $710 million. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.

It is not possible to predict with certainty the amount of additional investments in new or existing facilities or amounts of incremental operating costs to be incurred in the future to: prevent, control, reduce or eliminate releases of hazardous materials into the environment; comply with existing and new environmental laws and regulations; or remediate and restore areas damaged by prior releases of hazardous materials. Although these costs may be significant to the results of operations in any single period, the company does not expect them to have a material effect on the company’s liquidity or financial position.

CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS

Management makes many estimates and assumptions in the application of generally accepted accounting principles (GAAP) that may have a material impact on the company’s consolidated financial statements and related disclosures and on the comparability of such

FS-18

information over different reporting periods. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.

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

1. the nature of the estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change;

2. the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.

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

For example, the recording of deferred tax assets requires an assessment under the accounting rules that the future realization of the associated tax benefits be “more likely than not.” Another example is the estimation of 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,” beginning on page FS-63 for the changes in these estimates for the three years ending December 31, 2004, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves,” on page FS-68 for estimates of proved-reserve values for each year-end 2002–2004, 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 discussion of the critical accounting policy for “Impairment of Property, Plant and Equipment and Investments in Affiliates” on page FS-20 includes reference to conditions under which downward revisions of proved reserve quantities could result in impairments of oil and gas properties. This commentary should be read in conjunction with disclosures elsewhere in this discussion and in the Notes to the Consolidated Financial Statements related to estimates, uncertainties, contingencies and new accounting standards. Significant accounting policies are discussed in Note 1 to the Consolidated Financial Statements on page FS-30. The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed by management with the audit committee of the Board of Directors.

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

Pension and Other Postretirement Benefit Plans The determination of pension plan expense is based on a number of actuarial assumptions. Two critical assumptions are the expected long-

term rate of return on plan assets and the discount rate applied to pension plan obligations. For other postretirement employee benefit (OPEB) plans, which provide for certain health care and life insurance benefits for qualifying retired employees and which are not funded, critical assumptions in determining OPEB 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 22 to the Consolidated Financial Statements, beginning on page FS-46, includes information for the three years ending December 31, 2004, on the components of pension and OPEB expense and the underlying assumptions as well as on the funded status for the company’s pension plans at the end of 2004 and 2003.

To estimate the long-term rate of return on pension assets, the company employs a rigorous process that incorporates actual historical asset-class returns and an assessment of expected future performance and takes into consideration external actuarial advice and asset-class factors. Asset allocations are regularly updated using pension plan asset/liability studies, and the determination of the company’s estimates of long-term rates of return are consistent with these studies. For example, the expected long-term rate of return on United States pension plan assets, which account for about 70 percent of the company’s pension plan assets, has remained at 7.8 percent since 2002.

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

The discount rate assumptions used to determine pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality, fixed-income debt instruments. At December 31, 2004, the company calculated the U.S. pension obligation using a 5.8 percent discount rate. The discount rates used at the end of 2003 and 2002 were 6 percent and 6.8 percent, respectively.

An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa. Total pension expense for 2004 was $564 million. As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1 percent increase in the expected rate of return on assets of the company’s primary U.S. pension plan, which accounted for about 60 percent of the company-wide pension obligation, would have reduced total pension plan expense for 2004 by approximately $45 million. A 1 percent increase in the discount rate for this same plan would have reduced total benefit plan expense for 2004 by approximately $115 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.

In 2004, the company’s pension plan contributions totaled $1.6 billion (approximately $1.3 billion to the U.S. plans). In 2005, the company expects contributions to be approximately $400 million. Actual contribution amounts are dependent upon investment results, changes in pension obligations, regulatory environments and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations.

FS-19


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

Pension expense is recorded 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 a long-term liability is recorded. Any unfunded accumulated benefit obligation in excess of recorded liabilities is recorded in “Other comprehensive income.” See Note 22 to the Consolidated Financial Statements beginning on page FS-46 for the pension-related balance sheet effects at the end of 2004 and 2003.

For the company’s OPEB plans, expense for 2004 was $197 million and was also recorded as “Operating expenses” or “Selling, general and administrative expenses” in all business segments. At December 31, 2004, the discount rate applied to the company’s OPEB obligations was 5.8 percent – the same discount rate used for U.S. pension obligations. Effective January 1, 2005, the company amended its main U.S. postretirement medical plan to limit future increases in the company contribution. For current retirees, the increase in company contribution is capped at 4 percent each year. For future retirees, the 4 percent cap will be effective at retirement. Before retirement, the assumed health care cost trend rates start with 10.6 percent in 2004 and gradually drop to 4.8 percent for 2010 and beyond. Once the employee elects to retire, the trend rates are capped at 4 percent.

As an indication of discount rate sensitivity to the determination of OPEB expense in 2004, a 1 percent increase in the discount rate for the company’s primary U.S. OPEB plan, which accounted for about 90 percent of the companywide OPEB obligation, would have decreased OPEB expense by approximately $20 million.

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 crude oil and natural gas properties, significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its fair value.

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

The amount and income statement classification of major impairments of PP&E for the three years ending December 31, 2004, are included in the commentary on the business segments elsewhere in this discussion, as well as in Note 2 to the Consolidated Financial Statements beginning on page FS-32. 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 to the income statement for the difference between the investment’s carrying value and its estimated fair value at the time. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. Differing assumptions could affect whether an investment is impaired in any period and the amount of the impairment and are not subject to sensitivity analysis.

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

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 2 to the Consolidated Financial Statements on page FS-32 for the effect on earnings from losses associated with certain litigation and environmental remediation and tax matters for the three years ended December 31, 2004.

FS-20

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

American Jobs Creation Act of 2004 In October 2004, the American Jobs Creations Act of 2004 (the Act) was passed into law. The Act provides deduction from income for qualified domestic refining and upstream production activities, which will be phased in from 2005 through 2010. For that specific category of income, the company expects the net effect of this provision of the Act to result in a decrease in the federal effective tax rate for 2005 and 2006 to approximately 34 percent, based on current earnings levels. In the long term, the company expects that the new deduction will result in a decrease of the federal effective tax rate to about 32 percent for that category of income, based on current earnings levels.

Under the guidance in FASB Staff Position No. FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” the tax deduction on qualified production activities provided by the American Jobs Creation Act of 2004 will be treated as a “special deduction,” as described in FAS 109. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the period in which the deduction is claimed on the company’s tax return.

The Act also provides for a limited opportunity to repatriate earnings from outside the United States at a special reduced tax rate that can be as low as 5.25 percent. In early 2005, the company was in the process of reviewing the guidance that the IRS issued on January 13, 2005, regarding this provision and also considering other relevant information. The company does not anticipate a major change in its plans for repatriating earnings from international operations under the provisions of the Act.

NEW ACCOUNTING STANDARDS

FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46) In January 2003, FIN 46 was issued, and established standards for determining under what circumstances a variable interest entity (VIE) should be consolidated by 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. In December 2003, the FASB issued FIN 46-R, which not only includes amendments to FIN 46, but also requires application of the interpretation to all affected entities no later than March 31, 2004, for calendar year-reporting companies. Prior to this requirement, companies were required to apply the interpretation to special-purpose entities by December 31, 2003. The full adoption of the interpretation as of March 31, 2004, including the requirement relating to special-purpose entities, did not have a material impact on the company’s results of operations, financial position or liquidity.

FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” (FSP FAS 106-2) In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) became law. The Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care plans that provide a benefit that is at least actuarially equivalent to Medicare

Part D. In May 2004, the FASB issued FSP FAS 106-2. One U.S. subsidiary was deemed at least actuarially equivalent and eligible for the federal subsidy. The effect on the company’s postretirement benefit obligation and the associated annual expense was de minimis.

FASB Statement No. 151, “Inventory Costs, an Amendment of ARB No. 43, Chapter 4,” (FAS 151) In November 2004, the FASB issued FAS 151 which is effective for the company on January 1, 2006. The standard amends the guidance in Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and spoilage. In addition, the standard requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The company is currently evaluating the impact of this standard.

FASB Statement No. 123R, “Share-Based Payment” (FAS 123R) In December 2004, the FASB issued FAS 123R, which requires that compensation cost relating to share-based payments be recognized in the company’s financial statements. The company currently accounts for those payments under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The company is preparing to implement this standard effective July 1, 2005. Although the transition method to be used to adopt the standard has not been selected, the impact of adoption is expected to have a minimal impact on the company’s results of operations, financial position and liquidity. Refer to Note 1, beginning on page FS-30, for the company’s calculation of the pro forma impact on net income of FAS 123, which would be similar to that under FAS 123R.

FASB Statement No. 153, “Exchanges of Nonmonetary Assets — An Amendment of APB Opinion No. 29” (FAS 153) In December 2004, the FASB issued FAS 153, which is effective for the company for asset-exchange transactions beginning July 1, 2005. Under APB No. 29, assets received in certain types of nonmonetary exchanges were permitted to be recorded at the carrying value of the assets that were exchanged (i.e., recorded on a carryover basis). As amended by FAS 153, assets received in some circumstances will have to be recorded instead at their fair values. In the past, ChevronTexaco has not engaged in a large number of nonmonetary asset exchanges for significant amounts.

FS-21


	Quarterly Results and Stock Market Data

Unaudited


	2004																	2003		¹
Millions of dollars, except per-share amount	4TH Q		3RD Q		2ND Q		1ST Q			4TH Q		3RD Q			2ND Q			1ST Q

REVENUES AND OTHER INCOME
Sales and other operating revenues^2,3	$	41,612	$	39,611	$	36,579	$	33,063		$	30,018	$	30,058		$	28,982		$	30,517
Income from equity affiliates		785		613		740		444			262		287			216			264
Other income		295		496		924		138			67		147			52			42
Gain from exchange of Dynegy securities		–		–		–		–			–		365			–			–

TOTAL REVENUES AND OTHER INCOME		42,692		40,720		38,243		33,645			30,347		30,857			29,250			30,823

COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products		26,290		25,650		22,452		20,027			17,907		18,024			17,187			18,192
Operating expenses		2,874		2,557		2,234		2,167			2,488		2,227			1,853			1,932
Selling, general and administrative expenses		1,319		1,231		986		1,021			1,172		1,198			1,061			1,009
Exploration expenses		274		173		165		85			138		130			147			155
Depreciation, depletion and amortization		1,283		1,219		1,243		1,190			1,309		1,394			1,400			1,223
Taxes other than on income²		5,216		4,948		4,889		4,765			4,643		4,417			4,511			4,330
Interest and debt expense		112		107		94		93			111		115			118			130
Minority interests		22		23		18		22			14		24			20			22

TOTAL COSTS AND OTHER DEDUCTIONS		37,390		35,908		32,081		29,370			27,782		27,529			26,297			26,993

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		5,302		4,812		6,162		4,275			2,565		3,328			2,953			3,830
INCOME TAX EXPENSE		1,862		1,875		2,056		1,724			837		1,363			1,363			1,731

INCOME FROM CONTINUING OPERATIONS		3,440		2,937		4,106		2,551			1,728		1,965			1,590			2,099
INCOME FROM DISCONTINUED OPERATIONS		–		264		19		11			7		10			10			17

INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES	$	3,440	$	3,201	$	4,125	$	2,562		$	1,735	$	1,975		$	1,600		$	2,116

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, NET OF TAX		–		–		–		–			–		–			–			(196	)

NET INCOME⁴	$	3,440	$	3,201	$	4,125	$	2,562		$	1,735	$	1,975		$	1,600		$	1,920

PER-SHARE OF COMMON STOCK⁵
INCOME FROM CONTINUING OPERATIONS
– BASIC	$	1.64	$	1.38	$	1.93	$	1.21		$	0.82	$	1.00	⁶	$	0.75		$	0.98
– DILUTED	$	1.63	$	1.38	$	1.93	$	1.20		$	0.82	$	1.00	⁶	$	0.75		$	0.98

INCOME FROM DISCONTINUED OPERATIONS
– BASIC	$	–	$	0.13	$	0.01	$	–		$	–		0.01		$	–		$	0.01
– DILUTED	$	–	$	0.13	$	0.01	$	–		$	–		0.01		$	–		$	0.01

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
– BASIC	$	–	$	–	$	–	$	–		$	–		–		$	–		$	(0.09	)
– DILUTED	$	–	$	–	$	–	$	–		$	–		–		$	–		$	(0.09	)

NET INCOME
– BASIC	$	1.64	$	1.51	$	1.94	$	1.21		$	0.82	$	1.01	⁶	$	0.75		$	0.90
– DILUTED	$	1.63	$	1.51	$	1.94	$	1.20		$	0.82	$	1.01	⁶	$	0.75		$	0.90

DIVIDENDS	$	0.40	$	0.40	$	0.37	$	0.36		$	0.37	$	0.36		$	0.35		$	0.35
COMMON STOCK PRICE RANGE – HIGH	$	56.07	$	54.49	$	47.50	$	45.71		$	43.49	$	37.28		$	38.11		$	35.20
– LOW	$	50.99	$	46.21	$	43.95	$	41.99		$	35.57	$	35.02		$	31.06		$	30.65

¹ 2003 conformed to the 2004 presentation for discontinued operations.
² Includes consumer excise taxes:	$	2,150	$	2,040	$	1,921	$	1,857		$	1,825	$	1,814		$	1,765		$	1,691
³ Includes amounts for buy/sell contracts:	$	5,117	$	4,640	$	4,637	$	4,256		$	3,538	$	3,734		$	3,751		$	3,223
⁴ Net benefits (charges) for special items included in “Net Income”:	$	146	$	486	$	585	$	(55	)	$	89	$	14		$	(117	)	$	(39	)
⁵ The amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
⁶ Includes a benefit of $0.08 for the company’s share of a capital stock transaction of its Dynegy Inc. affiliate, which, under the applicable accounting rules, was recorded directly to retained earnings and not included in the net income for the period.

The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX) and on the Pacific Exchange. As of February 25, 2005, stockholders of record numbered approximately 227,000. There are no restrictions on the company’s ability to pay dividends.

FS-22

MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS

To the Stockholders of ChevronTexaco Corporation

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

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

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

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a–15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the company’s management concluded that its internal control over financial reporting was effective as of December 31, 2004.

The company management’s assessment of the effectiveness of its internal control over financial reporting as of December 31, 2004, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.


/s/ DAVID J. O’REILLY	/s/ STEPHEN J. CROWE	/s/ MARK A. HUMPHREY

DAVID J. O’REILLY	STEPHEN J. CROWE	MARK A. HUMPHREY
Chairman of the Board	Vice President	Vice President
and Chief Executive Officer	and Chief Financial Officer	and Comptroller
March 2, 2005

FS-23

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have completed an integrated audit of ChevronTexaco Corporation’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of ChevronTexaco Corporation and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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

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

As discussed in Note 25 on page FS-53 to the financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003.

/s/ PricewaterhouseCoopers LLP

San Francisco, California
March 2, 2005

FS-24


	Consolidated Statement of Income

Millions of dollars, except per-share amounts


	Year ended December 31
	2004		2003			2002

REVENUES AND OTHER INCOME
Sales and other operating revenues^1,2	$	150,865	$	119,575		$	98,340
Income (loss) from equity affiliates		2,582		1,029			(25	)
Other income		1,853		308			222
Gain from exchange of Dynegy preferred stock		–		365			–

TOTAL REVENUES AND OTHER INCOME		155,300		121,277			98,537

COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products²		94,419		71,310			57,051
Operating expenses		9,832		8,500			7,795
Selling, general and administrative expenses		4,557		4,440			4,155
Exploration expenses		697		570			591
Depreciation, depletion and amortization		4,935		5,326			5,169
Taxes other than on income¹		19,818		17,901			16,682
Interest and debt expense		406		474			565
Minority interests		85		80			57
Write-down of investments in Dynegy Inc.		–		–			1,796
Merger-related expenses		–		–			576

TOTAL COSTS AND OTHER DEDUCTIONS		134,749		108,601			94,437

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		20,551		12,676			4,100
INCOME TAX EXPENSE		7,517		5,294			2,998

INCOME FROM CONTINUING OPERATIONS		13,034		7,382			1,102
INCOME FROM DISCONTINUED OPERATIONS		294		44			30

INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES	$	13,328	$	7,426		$	1,132
Cumulative effect of changes in accounting principles		–		(196	)		–

NET INCOME	$	13,328	$	7,230		$	1,132

PER-SHARE OF COMMON STOCK³
INCOME FROM CONTINUING OPERATIONS
– BASIC	$	6.16	$	3.55		$	0.52
– DILUTED	$	6.14	$	3.55		$	0.52
INCOME FROM DISCONTINUED OPERATIONS
– BASIC	$	0.14	$	0.02		$	0.01
– DILUTED	$	0.14	$	0.02		$	0.01
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
– BASIC	$	–	$	(0.09	)	$	–
– DILUTED	$	–	$	(0.09	)	$	–
NET INCOME
– BASIC	$	6.30	$	3.48		$	0.53
– DILUTED	$	6.28	$	3.48		$	0.53

¹ Includes consumer excise taxes:	$	7,968	$	7,095		$	7,006
² Includes amounts in revenues for buy/sell contracts (associated costs are in “Purchased crude oil and products”) See Note 16 on page FS-41:	$	18,650	$	14,246		$	7,963
³ All periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
See accompanying Notes to the Consolidated Financial Statements.

FS-25


	Consolidated Statement of Comprehensive Income

Millions of dollars


	Year ended December 31
	2004			2003			2002

NET INCOME	$	13,328		$	7,230		$	1,132

Currency translation adjustment
Unrealized net change arising during period		36			32			15

Unrealized holding (loss) gain on securities
Net gain (loss) arising during period
Before income taxes		35			445			(149	)
Income taxes		–			–			52
Reclassification to net income of net realized (gain) loss
Before income taxes		(44	)		(365	)		217
Income taxes		–			–			(76	)

Total		(9	)		80			44

Net derivatives (loss) gain on hedge transactions
Before income taxes		(8	)		115			52
Income taxes		(1	)		(40	)		(18	)

Total		(9	)		75			34

Minimum pension liability adjustment
Before income taxes		719			12			(1,208	)
Income taxes		(247	)		(10	)		423

Total		472			2			(785	)

OTHER COMPREHENSIVE GAIN (LOSS), NET OF TAX		490			189			(692	)

COMPREHENSIVE INCOME	$	13,818		$	7,419		$	440

See accompanying Notes to the Consolidated Financial Statements.

FS-26


	Consolidated Balance Sheet

Millions of dollars, except per-share amounts


	At December 31
	2004			2003

ASSETS
Cash and cash equivalents	$	9,291		$	4,266
Marketable securities		1,451			1,001
Accounts and notes receivable (less allowance: 2004 – $174; 2003 – $179)		12,429			9,722
Inventories:
Crude oil and petroleum products		2,324			2,003
Chemicals		173			173
Materials, supplies and other		486			472

		2,983			2,648
Prepaid expenses and other current assets		2,349			1,789

TOTAL CURRENT ASSETS		28,503			19,426
Long-term receivables, net		1,419			1,493
Investments and advances		14,389			12,319
Properties, plant and equipment, at cost		103,954			100,556
Less: Accumulated depreciation, depletion and amortization		59,496			56,018

		44,458			44,538
Deferred charges and other assets		4,277			2,594
Assets held for sale		162			1,100

TOTAL ASSETS	$	93,208		$	81,470

LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt	$	816		$	1,703
Accounts payable		10,747			8,675
Accrued liabilities		3,410			3,172
Federal and other taxes on income		2,502			1,392
Other taxes payable		1,320			1,169

TOTAL CURRENT LIABILITIES		18,795			16,111
Long-term debt		10,217			10,651
Capital lease obligations		239			243
Deferred credits and other noncurrent obligations		7,942			7,758
Noncurrent deferred income taxes		7,268			6,417
Reserves for employee benefit plans		3,345			3,727
Minority interests		172			268

TOTAL LIABILITIES		47,978			45,175

Preferred stock (authorized 100,000,000 shares, $1.00 par value; none issued)		–			–
Common stock (authorized 4,000,000,000 shares, $0.75 par value; 2,274,032,014 and 2,274,042,114 shares issued at December 31, 2004 and 2003, respectively*)		1,706			1,706
Capital in excess of par value*		4,160			4,002
Retained earnings		45,414			35,315
Accumulated other comprehensive loss		(319	)		(809	)
Deferred compensation and benefit plan trust		(607	)		(602	)
Treasury stock, at cost (2004 – 166,911,890 shares; 2003 – 135,746,674 shares*)		(5,124	)		(3,317	)

TOTAL STOCKHOLDERS’ EQUITY		45,230			36,295

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	93,208		$	81,470


*	2003 restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.

See accompanying Notes to the Consolidated Financial Statements.

FS-27


	Consolidated Statement of Cash Flows

Millions of dollars


	Year ended December 31
	2004			2003			2002

OPERATING ACTIVITIES
Net income	$	13,328		$	7,230		$	1,132
Adjustments
Depreciation, depletion and amortization		4,935			5,326			5,169
Dry hole expense		286			256			288
Distributions (less) more than income from equity affiliates		(1,422	)		(383	)		510
Net before-tax gains on asset retirements and sales		(1,882	)		(194	)		(33	)
Net foreign currency effects		60			199			5
Deferred income tax provision		(224	)		164			(81	)
Net decrease in operating working capital		430			162			1,125
Minority interest in net income		85			80			57
Cumulative effect of changes in accounting principles		–			196			–
Gain from exchange of Dynegy preferred stock		–			(365	)		–
Write-down of investments in Dynegy, before tax		–			–			1,796
(Increase) decrease in long-term receivables		(60	)		12			(39	)
(Increase) decrease in other deferred charges		(69	)		1,646			428
Cash contributions to employee pension plans		(1,643	)		(1,417	)		(246	)
Other		866			(597	)		(168	)

NET CASH PROVIDED BY OPERATING ACTIVITIES		14,690			12,315			9,943

INVESTING ACTIVITIES
Capital expenditures		(6,310	)		(5,625	)		(7,597	)
Advances to equity affiliate		(2,200	)		–			–
Repayment of loans by equity affiliates		1,790			293			–
Proceeds from asset sales		3,671			1,107			2,341
Net (purchases) sales of marketable securities		(450	)		153			209

NET CASH USED FOR INVESTING ACTIVITIES		(3,499	)		(4,072	)		(5,047	)

FINANCING ACTIVITIES
Net borrowings (payments) of short-term obligations		114			(3,628	)		(1,810	)
Proceeds from issuances of long-term debt		–			1,034			2,045
Repayments of long-term debt and other financing obligations		(1,398	)		(1,347	)		(1,356	)
Cash dividends – common stock		(3,236	)		(3,033	)		(2,965	)
Dividends paid to minority interests		(41	)		(37	)		(26	)
Net (purchases) sales of treasury shares		(1,645	)		57			41
Redemption of preferred stock of subsidiaries		(18	)		(75	)		–

NET CASH USED FOR FINANCING ACTIVITIES		(6,224	)		(7,029	)		(4,071	)

EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS		58			95			15

NET CHANGE IN CASH AND CASH EQUIVALENTS		5,025			1,309			840
CASH AND CASH EQUIVALENTS AT JANUARY 1		4,266			2,957			2,117

CASH AND CASH EQUIVALENTS AT DECEMBER 31	$	9,291		$	4,266		$	2,957

See accompanying Notes to the Consolidated Financial Statements.

FS-28


	Consolidated Statement of Stockholders’ Equity

Shares in thousands; amounts in millions of dollars


	2004						2003						2002
	Shares			Amount			Shares			Amount			Shares			Amount

PREFERRED STOCK		–		$	–			–		$	–			–		$	–

COMMON STOCK*
Balance at January 1		2,274,042		$	1,706			2,274,042		$	1,706			2,274,042		$	1,706
Conversion of Texaco Inc. shares		(10	)		–			–			–			–			–

BALANCE AT DECEMBER 31		2,274,032		$	1,706			2,274,042		$	1,706			2,274,042		$	1,706

CAPITAL IN EXCESS OF PAR*
Balance at January 1				$	4,002					$	3,980					$	3,958
Treasury stock transactions					158						22						22

BALANCE AT DECEMBER 31				$	4,160					$	4,002					$	3,980

RETAINED EARNINGS
Balance at January 1				$	35,315					$	30,942					$	32,767
Net income					13,328						7,230						1,132
Cash dividends
Common stock					(3,236	)					(3,033	)					(2,965	)
Tax benefit from dividends paid on unallocated ESOP shares and other					7						6						8
Exchange of Dynegy securities					–						170						–

BALANCE AT DECEMBER 31				$	45,414					$	35,315					$	30,942

ACCUMULATED OTHER COMPREHENSIVE LOSS
Currency translation adjustment
Balance at January 1				$	(176	)				$	(208	)				$	(223	)
Change during year					36						32						15

Balance at December 31				$	(140	)				$	(176	)				$	(208	)
Minimum pension liability adjustment
Balance at January 1				$	(874	)				$	(876	)				$	(91	)
Change during year					472						2						(785	)

Balance at December 31				$	(402	)				$	(874	)				$	(876	)
Unrealized net holding gain on securities
Balance at January 1				$	129					$	49					$	5
Change during year					(9	)					80						44

Balance at December 31				$	120					$	129					$	49
Net derivatives gain on hedge transactions
Balance at January 1				$	112					$	37					$	3
Change during year					(9	)					75						34

Balance at December 31				$	103					$	112					$	37

BALANCE AT DECEMBER 31				$	(319	)				$	(809	)				$	(998	)

DEFERRED COMPENSATION AND BENEFIT PLAN TRUST
DEFERRED COMPENSATION
Balance at January 1				$	(362	)				$	(412	)				$	(512	)
Net reduction of ESOP debt and other					(5	)					50						100

BALANCE AT DECEMBER 31					(367	)					(362	)					(412	)
BENEFIT PLAN TRUST (COMMON STOCK)*		14,168			(240	)		14,168			(240	)		14,168			(240	)

BALANCE AT DECEMBER 31		14,168		$	(607	)		14,168		$	(602	)		14,168		$	(652	)

TREASURY STOCK AT COST*
Balance at January 1		135,747		$	(3,317	)		137,769		$	(3,374	)		139,601		$	(3,415	)
Purchases		42,607			(2,122	)		81			(3	)		76			(3	)
Issuances – mainly employee benefit plans		(11,442	)		315			(2,103	)		60			(1,908	)		44

BALANCE AT DECEMBER 31		166,912		$	(5,124	)		135,747		$	(3,317	)		137,769		$	(3,374	)

TOTAL STOCKHOLDERS’ EQUITY AT DECEMBER 31				$	45,230					$	36,295					$	31,604


*	2003 and 2002 restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.

See accompanying Notes to the Consolidated Financial Statements.

FS-29


	Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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, chemicals and coal mining operations. In addition, ChevronTexaco holds investments in the power generation business. Collectively, these companies conduct business activities in more than 180 countries. Exploration and production (upstream) operations consist of exploring for, developing and producing crude oil and natural gas and also marketing natural gas. Refining, marketing and transportation (downstream) operations relate to refining crude oil into finished petroleum products; marketing crude oil, natural gas and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipeline, marine vessel, motor equipment and rail car. Chemical operations include the manufacture and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant oil additives.

The company’s Consolidated Financial Statements are prepared in accordance with principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as future confirming events occur.

The nature of the company’s operations and the many countries in which it operates subject the company to changing economic, regulatory and political conditions. The company does not believe it is vulnerable to the risk of near-term severe impact as a result of any concentration of its activities.

Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent owned and variable interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent or for which the company exercises significant influence but not control over policy decisions are accounted for by the equity method. As part of that accounting, the company recognizes gains and losses that arise from the issuance of stock by an affiliate that results in changes in the company’s proportionate share of the dollar amount of the affiliate’s equity currently in income. Deferred income taxes are provided for these gains and losses.

Investments are assessed for possible impairment when events indicate that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and

intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value. Subsequent recoveries in the carrying value of other investments are reported in “Other comprehensive income.”

Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the various factors giving rise to the difference. The company’s share of the affiliate’s reported earnings is adjusted quarterly when appropriate to reflect the difference between these allocated values and the affiliate’s historical book values.

Derivatives The majority of the company’s activity in commodity derivative instruments is intended to manage the 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 or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s 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 securities. Those investments that are part of the company’s cash management portfolio and have original maturities of three months or less are reported as “Cash equivalents.” The balance of the short-term investments is reported as “Marketable securities.” Short-term investments are marked-to-market, with any unrealized gains or losses included in “Other comprehensive income.”

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

Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs are also capitalized for wells that find commercially producible reserves that cannot be classified as proved, pending

FS-30

4 NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

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. Refer to Note 21 on page FS-45 for additional discussion of accounting for suspended exploratory well costs.

Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted future net before-tax cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset, significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted future net before-tax cash flows. For proved crude oil and natural gas properties in the United States, the company generally performs the impairment review on an individual field basis. Outside the United States, reviews are performed on a country, concession or field basis, as appropriate. Globally in the refining, marketing, transportation and chemical areas, impairment reviews are generally done on a refinery, plant, marketing area or marketing assets by country basis. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense.

Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value.

Effective January 1, 2003, the company implemented Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations (FAS 143),” in which the fair value of a liability for an asset retirement obligation is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 25 on page FS-53 relating to asset retirement obligations, which includes additional information on the company’s adoption of FAS 143. Previously, for crude oil, natural gas and coal producing properties, a provision was made through depreciation expense for anticipated abandonment and restoration costs at the end of the property’s useful life.

Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method by individual field as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed.

Depreciation and depletion expenses for coal assets 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 or cleanups or both are probable and the costs can be reasonably estimated. For the company’s U.S. and Canadian marketing facilities, the accrual is based in part on the probability that a future remediation commitment will be required. For oil, gas and coal producing properties, a liability for an asset retirement obligation is made, following FAS 143. Refer to “Properties, Plant and Equipment” in this note for a discussion of FAS 143.

For federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares.

The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured.

Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency translations are currently included in income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in the currency translation adjustment in “Stockholders’ equity.”

Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which ChevronTexaco has an interest with other producers are generally recognized on the basis of the company’s net working interest (entitlement method). Refer to Note 16 on page FS-41 for a discussion of the accounting for buy/sell arrangements.

Stock Compensation At December 31, 2004, the company had stock-based employee compensation plans, which are described

FS-31


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

4 NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

more fully in Note 22 beginning on page FS-46. 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 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
	2004			2003			2002

Net income, as reported	$	13,328		$	7,230		$	1,132
Add: Stock-based employee compensation expense included in reported net income determined under APB No. 25, net of related tax effects¹		10			1			(1	)
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects ^1,2		(52	)		(26	)		(47	)

Pro forma net income	$	13,286		$	7,205		$	1,084

Earnings per share^3,4
Basic – as reported	$	6.30		$	3.48		$	0.53
Basic – pro forma	$	6.28		$	3.47		$	0.51
Diluted – as reported	$	6.28		$	3.48		$	0.53
Diluted – pro forma	$	6.26		$	3.47		$	0.51


¹	Costs of stock appreciation rights reported in net income and included in the fair-value method for these rights were $10, $1 and $(1) for 2004, 2003 and 2002, respectively.


²	The fair value is estimated using the Black-Scholes option-pricing model for stock options. Stock appreciation rights are estimated based on the method outlined in SFAS 123 for these instruments.


³	Per-share amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.


⁴	The amounts in 2003 include a benefit of $0.08 for the company’s share of a capital stock transaction of its Dynegy Inc. affiliate, which under the applicable accounting rules was recorded directly to the company’s retained earnings and not included in net income for the period.

Refer to Note 20 beginning on page FS-44 for a discussion of the company’s plan to implement FASB statement No. 123R, “Share-Based Payment,” effective July 1, 2005.

NOTE 2.
SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION

Net income for each period presented includes amounts categorized by the company as “special items,” to assist in the 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.

In 2004, the company recorded special gains of $1,217 from the sale of nonstrategic crude oil and natural gas assets, primarily in the United States and Canada, and a special charge of $55 for a litigation matter.

In 2003, impairments of $103 and $30, respectively, were recorded for various U.S. and international oil and gas producing properties, reflecting lower expected recovery of proved reserves or a write-down to market value for assets in anticipation of sale. Impairments of $123 on downstream assets were for

the conversion of a refinery to a products terminal and a write-down to market value for assets in anticipation of sale. Also in 2003, ChevronTexaco exchanged its Dynegy Series B Preferred Stock for cash, notes and Series C Preferred Stock. The $365 difference between the fair value of these items and the company’s carrying value was included in net income.

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 14 beginning on page FS-39 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.


	Year ended December 31
	2004			2003			2002

Special Items
Asset dispositions
Exploration and Production
Continuing operations
United States		316			77			–
International		644			32			–
Discontinued operations
United States		50			–			–
International		207			–			–
Refining, Marketing and Transportation
United States		–			37			–
International		–			(24	)		–

		1,217			122			–
Asset impairments/write-offs
Exploration and Production
Continuing operations
United States		–			(103	)		(183	)
International		–			(30	)		(100	)
Refining, Marketing and Transportation
United States		–			–			(66	)
International		–			(123	)		(136	)
All Other
Other asset write-offs		–			(84	)		–

		–			(340	)		(485	)

Tax adjustments		–			118			60
Environmental remediation provisions		–			(132	)		(160	)
Restructuring and reorganizations		–			(146	)		–
Merger-related expenses		–			–			(386	)
Litigation provisions		(55	)		–			(57	)

Dynegy-related
Impairments – equity share		–			(40	)		(531	)
Asset dispositions – equity share		–			–			(149	)
Other		–			365			(1,626	)

		–			325			(2,306	)

Total Special Items	$	1,162		$	(53	)	$	(3,334	)

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

FS-32

4 NOTE 2. SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION – Continued


	Year ended December 31
	2004		2003			2002

Revenues and other income
Income (loss) from equity affiliates	$	–	$	179		$	(829	)
Other income		1,281		(148	)		–
Gain from exchange of Dynegy preferred stock		–		365			–

Total revenues and other income		1,281		396			(829	)

Costs and other deductions
Operating expenses		85		329			259
Selling, general and administrative expenses		–		146			180
Depreciation, depletion and amortization		–		286			298
Write-down of investments in Dynegy Inc.		–		–			1,796
Merger-related expenses		–		–			576

Total costs and other deductions		85		761			3,109

Income from continuing operations before income tax expense		1,196		(365	)		(3,938	)
Income tax expense (benefit)		291		(312	)		(604	)

Income from continuing operations		905		(53	)		(3,334	)
Income from discontinued operations		257		–			–

Net income	$	1,162	$	(53	)	$	(3,334	)

Other financial information is as follows:


	Year ended December 31
	2004			2003			2002

Total financing interest and debt costs	$	450		$	549		$	632
Less: Capitalized interest		44			75			67

Interest and debt expense	$	406		$	474		$	565

Research and development expenses	$	242		$	228		$	221
Foreign currency effects*	$	(81	)	$	(404	)	$	(43	)


*	Includes $(13), $(96) and $(66) in 2004, 2003 and 2002, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The excess of market value over the carrying value of inventories for which the LIFO method is used was $3,036, $2,106 and $1,571 at December 31, 2004, 2003 and 2002, respectively. Market value is generally based on average acquisition costs for the year. LIFO profits of $36, $82 and $13 were included in net income for the years 2004, 2003 and 2002, respectively.

NOTE 3.
COMMON STOCK SPLIT

On July 28, 2004, the company’s Board of Directors approved a two-for-one stock split in the form of a stock dividend to the company’s stockholders of record on August 19, 2004, with distribution of shares on September 10, 2004. The total number of authorized common stock shares and associated par value were unchanged by this action. All per-share amounts in the financial statements reflect the stock split for all periods presented. The effect of the common stock split is reflected on the Consolidated Balance Sheet in “Common stock” and “Capital in excess of par value.”

NOTE 4.
INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS

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


	Year ended December 31
	2004			2003			2002

Increase in accounts and notes receivable	$	(2,515	)	$	(265	)	$	(1,135	)
(Increase) decrease in inventories		(298	)		115			185
(Increase) decrease in prepaid expenses and other current assets		(76	)		261			92
Increase in accounts payable and accrued liabilities		2,175			242			1,845
Increase (decrease) in income and other taxes payable		1,144			(191	)		138

Net decrease in operating working capital	$	430		$	162		$	1,125

Net cash provided by operating activities includes the following cash payments for interest and income taxes:
Interest paid on debt (net of capitalized interest)	$	422		$	467		$	533
Income taxes	$	6,679		$	5,316		$	2,916

Net (purchases) sales of marketable securities consist of the following gross amounts:
Marketable securities purchased	$	(1,951	)	$	(3,563	)	$	(5,789	)
Marketable securities sold		1,501			3,716			5,998

Net (purchases) sales of marketable securities	$	(450	)	$	153		$	209

The 2003 “Net cash provided by operating activities” included an $890 “Decrease in other deferred charges” and a decrease of the same amount in “Other” related to balance sheet netting of certain pension-related asset and liability accounts, in accordance with the requirements of Financial Accounting Standards Board (FASB) Statement No. 87, “Employers’ Accounting for Pensions.”

The “Net (purchases) sales of treasury shares” in 2004 included share repurchases of $2.1 billion related to the company’s common stock repurchase program, which were partially offset by the issuance of shares for the exercise of stock options.

The major components of “Capital expenditures” and the reconciliation of this amount to the reported capital and exploratory expenditures, including equity affiliates, presented in MD&A are presented in the following table.

FS-33


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

4 NOTE 4. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS – Continued


	Year ended December 31
	2004			2003			2002

Additions to properties, plant and equipment¹	$	5,798		$	4,953		$	6,262
Additions to investments		303			687			1,138
Current-year dry hole expenditures		228			132			252
Payments for other liabilities and assets, net		(19	)		(147	)		(55	)

Capital expenditures		6,310			5,625			7,597
Expensed exploration expenditures		412			315			303
Payments of long-term debt and other financing obligations, net		31			286	²		2

Capital and exploratory expenditures, excluding equity affiliates		6,753			6,226			7,902
Equity in affiliates’ expenditures		1,562			1,137			1,353

Capital and exploratory expenditures, including equity affiliates	$	8,315		$	7,363		$	9,255


¹	Net of noncash additions of $212 in 2004, $1,183 in 2003 and $195 in 2002.


²	Includes deferred payment of $210 related to the 1993 acquisition of the company’s interest in the Tengizchevroil joint venture.

NOTE 5.
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. Assets include those related to the exploration and production of crude oil, natural gas and natural gas liquids and those associated with the refining, marketing, supply and distribution of products derived from petroleum, other than natural gas liquids, excluding most of the regulated pipeline operations of ChevronTexaco. CUSA also holds ChevronTexaco’s investments in the ChevronPhillips Chemical Company LLC (CPChem) joint venture and Dynegy Inc. (Dynegy), which are accounted for using the equity method.

During 2003 and 2002, ChevronTexaco implemented legal reorganizations 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 following table 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, 2002. However, the financial information included in this table 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, 2002.


	Year ended December 31
	2004		2003		2002

Sales and other operating revenues	$	108,351	$	82,760	$	66,835
Total costs and other deductions		102,180		78,399		68,526
Net income (loss)*		4,773		3,083		(1,895	)


*	2003 net income includes a charge of $323 for the cumulative effect of changes in accounting principles.


	At December 31
	2004		2003

Current assets	$	23,147	$	15,539
Other assets*		19,961		21,348
Current liabilities		17,044		13,122
Other liabilities		12,533		14,136
Net equity		13,531		9,629

Memo: Total debt	$	8,349	$	9,091


*	Includes assets held for sale of $1,052 at December 31, 2003.

CUSA’s net loss of $1,895 for 2002 included net charges of $2,555 for asset write-downs and dispositions, of which $2,306 was related to Dynegy.

NOTE 6.
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 connection with certain debt securities issued by a third party. Summarized financial information for CTC and its consolidated subsidiaries is presented in the following table:


	Year ended December 31
	2004		2003		2002

Sales and other operating revenues	$	660	$	601	$	850
Total costs and other deductions		495		535		922
Net income (loss)		160		50		(79	)


	At December 31
	2004		2003

Current assets	$	292	$	116
Other assets		219		312
Current liabilities		67		96
Other liabilities		278		243
Net equity		166		89

During 2004, CTC’s paid-in capital decreased by $85 from capital settlements.

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at December 31, 2004.

NOTE 7.
STOCKHOLDERS’ EQUITY

Retained earnings at December 31, 2004 and 2003, included approximately $3,950 and $1,300, respectively, for the company’s share of undistributed earnings of equity affiliates.

At December 31, 2004, about 151 million shares of ChevronTexaco’s common stock remain available for issuance

FS-34

4 NOTE 7. STOCKHOLDERS’ EQUITY – Continued

from the 160 million shares that were reserved for issuance under the ChevronTexaco Corporation Long-Term Incentive Plan (LTIP), as amended and restated, which was approved by the stockholders in 2004. In addition, approximately 622 thousand shares remain available for issuance from the 800 thousand shares of the company’s common stock that were reserved for awards under the ChevronTexaco Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan (Non-Employee Directors’ Plan), which was approved by stockholders in 2003.

Refer to Note 3 on page FS-33 for a discussion of the company’s common stock split.

NOTE 8.
FINANCIAL AND DERIVATIVE INSTRUMENTS

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

The company uses financial 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 financial 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” marked-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.

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 2004, four new swaps relating to a portion of the company’s fixed-rate debt were initiated. At year-end 2004, the interest rate swaps outstanding related to fixed-rate debt, and their weighted average maturity was approximately three years.

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

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 $5,815 and $7,229 had estimated fair values of $6,444 and $7,709 at December 31, 2004 and 2003, respectively.

For interest rate swaps, the notional principal amounts of $1,665 and $665 had estimated fair values of $36 and $65 at December 31, 2004 and 2003, 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 $8,789 and $3,803 at December 31, 2004 and 2003, respectively. Of these balances, $7,338 and $2,803 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 2.3 years.

For the financial and derivative instruments discussed above, there was not a material change in market risk from that presented in 2003.

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

FS-35


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

4 NOTE 8. FINANCIAL AND DERIVATIVE INSTRUMENTS – Continued

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.

Investment in Dynegy Notes and Preferred Stock At the beginning of 2004, the company held investments in $223 face value of Dynegy Junior Unsecured Subordinated Notes due 2016 and $400 face value of Dynegy Series C Convertible Preferred Stock with a stated maturity date of 2033.

The Junior Notes were redeemed at face value during 2004, and gains of $54 were recorded for the difference between the face amounts and the carrying values at the time of redemption. The face value of the company’s investment in the Series C preferred stock at December 31, 2004, was $400. The stock is recorded at its fair value, which was estimated to be $370 at December 31, 2004. Future temporary changes in the estimated fair value of the preferred stock will be reported in “Other comprehensive income.” However, if any future decline in fair value is deemed to be other than temporary, a charge against income in the period would be recorded. Dividends payable on the preferred stock are recognized in income each period.

NOTE 9.
OPERATING SEGMENTS AND GEOGRAPHIC DATA

Although each subsidiary of ChevronTexaco is responsible for its own affairs, ChevronTexaco Corporation manages its investments in these subsidiaries and their affiliates. For this purpose, the investments are grouped as follows: upstream – exploration and production; downstream – refining, marketing and transportation; chemicals; and all other. The first three of these groupings represent the company’s “reportable segments” and “operating segments” as defined in FAS 131, “Disclosures About Segments of an Enterprise and Related Information.”

The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) (terms as defined in FAS 131). The CODM is the company’s Executive Committee, a committee of senior officers that includes the Chief Executive Officer and that in turn reports to the Board of Directors of ChevronTexaco Corporation.

The operating segments represent components of the company as described in FAS 131 terms that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments, and to assess their performance; and (c) for which discrete financial information is available.

Segment managers for the reportable segments are directly accountable to and maintain regular contact with the company’s CODM to discuss the segment’s operating activities and financial performance. The CODM approves annual capital and exploratory budgets at the reportable segment level and also approves capital and exploratory funding for major projects and major changes to the annual capital and exploratory budgets. However, business-unit managers within the operating segments are directly responsible for decisions relating to project implementation and all

other matters connected with daily operations. Company officers who are members of the Executive Committee also have individual management responsibilities and participate in other committees for purposes other than acting as the CODM.

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

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 remain at the corporate level in “All Other.” Merger-related expenses in 2002 were also included in “All Other.” After-tax segment income (loss) from continuing operations is presented in the following table:


	Year ended December 31
	2004			2003			2002

Income From Continuing Operations
Upstream – Exploration and Production
United States	$	3,868		$	3,160		$	1,703
International		5,622			3,199			2,823

Total Exploration and Production		9,490			6,359			4,526

Downstream – Refining, Marketing and Transportation
United States		1,261			482			(398	)
International		1,989			685			31

Total Refining, Marketing and Transportation		3,250			1,167			(367	)

Chemicals
United States		251			5			13
International		63			64			73

Total Chemicals		314			69			86

Total Segment Income		13,054			7,595			4,245

All Other
Interest expense		(257	)		(352	)		(406	)
Interest income		129			75			72
Other		108			64			(2,423	)
Merger-related expenses		–			–			(386	)

Income From Continuing Operations		13,034			7,382			1,102
Income From Discontinued Operations		294			44			30
Cumulative effect of changes in accounting principles		–			(196	)		–

Net Income	$	13,328		$	7,230		$	1,132

FS-36

4 NOTE 9. OPERATING SEGMENTS AND GEOGRAPHIC DATA – Continued

Segment Assets Segment assets do not include intercompany investments or intercompany receivables. Segment assets at year-end 2004 and 2003 follow:


	At December 31
	2004		2003

Upstream – Exploration and Production
United States	$	11,869	$	12,501
International		31,239		28,520

Total Exploration and Production		43,108		41,021

Downstream – Refining, Marketing and Transportation
United States		10,091		9,354
International		19,415		17,627

Total Refining, Marketing and Transportation		29,506		26,981

Chemicals
United States		2,316		2,165
International		667		662

Total Chemicals		2,983		2,827

Total Segment Assets		75,597		70,829

All Other*
United States		11,746		6,644
International		5,865		3,997

Total All Other		17,611		10,641

Total Assets – United States		36,022		30,664
Total Assets – International		57,186		50,806

Total Assets	$	93,208	$	81,470


*	All Other assets consist primarily of worldwide cash, cash equivalents and marketable securities, real estate, information systems, the company’s investment in Dynegy, coal mining operations, power generation businesses, technology companies, and assets of the corporate administrative functions.

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2004, 2003 and 2002 are presented in the following table. Products are transferred between operating segments at internal product values that approximate market prices.

Revenues for the upstream segment are derived primarily from the production of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products, such as gasoline, jet fuel, gas oils, kerosene, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the transportation and trading of crude oil and refined products. Revenues for the chemicals segment are derived primarily from the manufacture and sale of additives for lubricants and fuel. “All Other” activities include revenues from coal mining operations, power generation businesses, insurance operations, real estate activities and technology companies.

Other than the United States, the only country where ChevronTexaco generates significant revenues is the United Kingdom, where revenues amounted to $13,985, $12,121 and $10,816 in 2004, 2003 and 2002, respectively.


	Year ended December 31
	2004			2003			2002

Upstream – Exploration and Production
United States	$	8,242		$	6,842		$	4,923
Intersegment		8,121			6,295			4,217

Total United States		16,363			13,137			9,140

International		7,246			7,013			5,360
Intersegment		10,184			8,142			8,301

Total International		17,430			15,155			13,661

Total Exploration and Production		33,793			28,292			22,801

Downstream – Refining, Marketing and Transportation
United States		57,723			44,701			33,881
Excise taxes		4,147			3,744			3,990
Intersegment		179			225			163

Total United States		62,049			48,670			38,034

International		67,944			52,486			45,759
Excise taxes		3,810			3,342			3,006
Intersegment		87			46			38

Total International		71,841			55,874			48,803

Total Refining, Marketing and Transportation		133,890			104,544			86,837

Chemicals
United States		347			323			323
Intersegment		188			129			109

Total United States		535			452			432

International		747			677			638
Excise taxes		11			9			10
Intersegment		107			83			68

Total International		865			769			716

Total Chemicals		1,400			1,221			1,148

All Other
United States		551			338			413
Intersegment		431			121			105

Total United States		982			459			518

International		97			100			37
Intersegment		82			4			–

Total International		179			104			37

Total All Other		1,161			563			555

Segment Sales and Other Operating Revenues
United States		79,929			62,718			48,124
International		90,315			71,902			63,217

Total Segment Sales and Other Operating Revenues		170,244			134,620			111,341
Elimination of intersegment sales		(19,379	)		(15,045	)		(13,001	)

Total Sales and Other Operating Revenues	$	150,865		$	119,575		$	98,340

FS-37


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

4 NOTE 9. OPERATING SEGMENTS AND GEOGRAPHIC DATA – Continued

Segment Income Taxes Segment income tax expenses for the years 2004, 2003 and 2002 are as follows:


	Year ended December 31
	2004			2003¹			2002

Upstream – Exploration and Production
United States	$	2,308		$	1,853		$	854
International		5,041			3,831			3,415

Total Exploration and Production		7,349			5,684			4,269

Downstream – Refining, Marketing and Transportation
United States		739			300			(254	)
International		442			275			138

Total Refining, Marketing and Transportation		1,181			575			(116	)

Chemicals
United States		47			(25	)		(17	)
International		17			6			17

Total Chemicals		64			(19	)		–

All Other		(1,077	)		(946	)		(1,155	)

Income Tax Expense From Continuing Operations²	$	7,517		$	5,294		$	2,998


¹	See Note 25 on page FS-53 for information concerning the cumulative effect of changes in accounting principles due to the adoption of FAS 143, “Accounting for Asset Retirement Obligations.”


²	Income tax expense of $100, $50 and $26 related to discontinued operations for 2004, 2003 and 2002, respectively, is not included.

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 14 beginning on page FS-39. Information related to properties, plant and equipment by segment is contained in Note 15 on page FS-41.

NOTE 10.
LITIGATION

The company and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive.

NOTE 11.
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
	2004		2003

Exploration and Production	$	277	$	246
Refining, Marketing and Transportation		842		842

Total		1,119		1,088
Less: Accumulated amortization		690		642

Net capitalized leased assets	$	429	$	446

Rental expenses incurred for operating leases during 2004, 2003 and 2002 were as follows:


	Year ended December 31
	2004		2003		2002

Minimum rentals	$	2,093	$	1,567	$	1,270
Contingent rentals		7		3		4

Total		2,100		1,570		1,274
Less: Sublease rental income		40		48		53

Net rental expense	$	2,060	$	1,522	$	1,221

Contingent rentals are based on factors other than the passage of time, principally sales volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, renewal options ranging up to 25 years, and options to purchase the leased property during or at the end of the initial or renewal lease period for the fair market value or other specified amount at that time.

At December 31, 2004, 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: 2005	$	390	$	83
2006		338		74
2007		280		62
2008		239		51
2009		236		52
Thereafter		749		562

Total	$	2,232	$	884

Less: Amounts representing interest and executory costs				(292	)

Net present values				592
Less: Capital lease obligations included in short-term debt				(353	)

Long-term capital lease obligations			$	239

FS-38

4NOTE 12. RESTRUCTURING AND REORGANIZATION COSTS

NOTE 12.
RESTRUCTURING AND REORGANIZATION COSTS

In connection with various reorganizations and restructurings across several businesses and corporate departments, the company recorded before-tax charges of $258 ($146 after tax) during 2003 for estimated termination benefits for approximately 4,500 employees. Nearly half of the liability related to the global downstream segment. Substantially all of the employee reductions are expected to occur by the end of 2005.

At the beginning of 2004, a $100 liability remained for employee severance charges recorded in 2002 and 2001 associated with the merger between Chevron Corporation and Texaco Inc. The balance related primarily to deferred payment options elected by certain employees who were terminated before the end of 2003. Approximately $80 of the liability was paid during 2004 and the remainder in January 2005.

Activity for the company’s liability related to reorganizations and restructurings in 2004 is summarized in the following table:


Amounts before tax	2004			2003

Balance at January 1	$	240		$	6
Additions		27			258
Payments		(148	)		(24	)

Balance at December 31	$	119		$	240

Substantially all of the balance at December 31, 2004, related to employee severance costs that were part of a presumed ongoing benefit arrangement under applicable accounting rules in FAS 146, “Accounting for Costs Associated with Exit or Disposal Activities,” paragraph 8, footnote 7. Therefore, the company accounts for severance costs in accordance with FAS 88, “Employers’ Accounting for Settlements and Curtailments of Defined Pension Plans and for Termination Benefits.” At December 31, 2004, the amount was categorized as a current accrued liability on the Consolidated Balance Sheet and the associated charges during the period were categorized as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income.

NOTE 13.
ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS

At December 31, 2004, and December 31, 2003, the company classified $162 and $1,100, respectively, of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. Assets in this category at the end of 2004 related to a group of service stations. These assets are expected to be disposed of in 2005.

Summarized income statement information relating to discontinued operations is as follows:


	Year ended December 31
	2004		2003		2002

Revenues and other income	$	635	$	485	$	376
Income from discontinued operations before income tax expense		394		94		56
Income from discontinued operations, net of tax		294		44		30

Included in the 2004 after-tax amount were gains totaling $257 related to the sale of a Canadian natural-gas processing business, a wholly owned subsidiary in the Democratic Republic of the Congo and certain producing properties in the Gulf of Mexico.

Not all assets sold or to be disposed of are classified as discontinued operations, mainly because the cash flows from the assets were not/will not be eliminated from the ongoing operations of the company.

NOTE 14.
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
	2004		2003		2004		2003			2002

Upstream – Exploration and Production
Tengizchevroil	$	4,725	$	3,363	$	950	$	611		$	490
Other		1,177		991		246		200			116

Total Exploration and Production		5,902		4,354		1,196		811			606

Downstream – Refining, Marketing and Transportation
LG-Caltex Oil Corporation		1,820		1,561		296		107			46
Caspian Pipeline Consortium		1,039		1,026		140		52			66
Star Petroleum Refining Company Ltd.		663		457		207		8			(25	)
Caltex Australia Ltd.		263		118		173		13			(156	)
Other		1,125		1,069		143		100			110

Total Refining, Marketing and Transportation		4,910		4,231		959		280			41

Chemicals
Chevron Phillips Chemical Company LLC		1,896		1,747		334		24			2
Other		19		20		2		1			4

Total Chemicals		1,915		1,767		336		25			6

All Other
Dynegy Inc.		525		698		86		(56	)		(679	)
Other		601		761		5		(31	)		1

Total equity method	$	13,853	$	11,811	$	2,582	$	1,029		$	(25	)
Other at or below cost		536		508

Total investments and advances	$	14,389	$	12,319

Total U.S.	$	3,788	$	3,905	$	588	$	175		$	(559	)
Total International	$	10,601	$	8,414	$	1,994	$	854		$	534

Descriptions of major affiliates are as follows:

Tengizchevroil ChevronTexaco has a 50 percent equity ownership interest in TCO, a joint venture formed in 1993 to develop the Tengiz and Korolev oil fields in Kazakhstan over a 40-year period.

In 2004, as part of the funding of the expansion of TCO’s production facilities, ChevronTexaco purchased from TCO $2,200 of 6.124 percent Series B Notes, due 2014, guaranteed by TCO. Interest on the notes is payable semiannually and principal is to be repaid semiannually in equal installments beginning in February 2008. Immediately following the purchase of the Series B Notes, ChevronTexaco received from TCO approximately $1,800 representing a repayment of subordinated loans from the company, interest and dividends. The $2,200 investment in the Series B Notes, which the company intends to hold to their

FS-39


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

4 NOTE 14. INVESTMENTS AND ADVANCES – Continued

maturity, and the $1,800 distribution were recorded to “Investments and Advances.”

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 and petrochemicals 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 Map 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, 2004, the fair value of ChevronTexaco’s share of CAL common stock was $1,130. The aggregate carrying value of the company’s investment in CAL was approximately $80 lower than the amount of underlying equity in CAL net assets.

Chevron Phillips Chemical Company LLC ChevronTexaco owns 50 percent of CPChem, formed in 2000 when Chevron merged most of its petrochemicals businesses with those of Phillips Petroleum Company. At December 31, 2004, the company’s carrying value of its investment in CPChem was approximately $130 lower than the amount of underlying equity in CPChem’s net assets.

Dynegy Inc. ChevronTexaco owns an approximate 25 percent equity interest in the common stock of Dynegy, an energy provider engaged in power generation, the gathering and processing

of natural gas, and the fractionation, storage, transportation and marketing of natural gas liquids. The company also holds investments in Dynegy preferred stock.

Investment in Dynegy Common Stock At December 31, 2004, the carrying value of the company’s investment in Dynegy common stock was approximately $150. This amount was about $365 below the company’s proportionate interest in Dynegy’s underlying net assets. This difference is primarily the result of write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value that were deemed to be other than temporary. This difference has been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors contributing to the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly when appropriate to reflect the difference between these allocated values and Dynegy’s historical book values. The market value of the company’s investment in Dynegy’s common stock at December 31, 2004, was approximately $450.

Investments in Dynegy Notes and Preferred Stock Refer to Note 8 on page FS-35 for a discussion of these investments.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $7,933, $6,308 and $6,522 with affiliated companies for 2004, 2003 and 2002, respectively. “Purchased crude oil and products” includes $2,548, $1,740 and $1,839 with affiliated companies for 2004, 2003 and 2002, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $1,188 and $827 due from affiliated companies at December 31, 2004 and 2003, respectively. “Accounts payable” includes $192 and $118 due to affiliated companies at December 31, 2004 and 2003, respectively.

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


	Affiliates							ChevronTexaco Share*
Year ended December 31	2004		2003		2002			2004		2003		2002

Total revenues	$	55,152	$	42,323	$	31,877		$	25,916	$	19,467	$	15,049
Income (loss) before income tax expense		5,309		1,657		(1,517	)		3,015		1,211		70
Net income (loss)		4,441		1,508		(1,540	)		2,582		1,029		(25	)

At December 31

Current assets	$	16,506	$	12,204	$	16,808		$	7,540	$	5,180	$	6,270
Noncurrent assets		38,104		39,422		40,884			15,567		15,765		15,219
Current liabilities		10,949		9,642		14,414			4,962		4,132		5,158
Noncurrent liabilities		22,261		22,738		24,129			4,520		5,002		5,668

Net equity	$	21,400	$	19,246	$	19,149		$	13,625	$	11,811	$	10,663


*	The company’s share of income and underlying equity in the net assets of its investments includes the effects of write-downs of certain investments, largely related to Dynegy Inc. and Caltex Australia Ltd., as described in the preceding section.

FS-40

4 NOTE 15. PROPERTIES, PLANT AND EQUIPMENT

NOTE 15.
PROPERTIES, PLANT AND EQUIPMENT¹


	At December 31												Year ended December 31
	Gross Investment at Cost						Net Investment²						Additions at Cost³						Depreciation Expense^4,5
	2004		2003		2002		2004		2003		2002		2004		2003		2002		2004		2003		2002

Exploration and Production
United States	$	37,329	$	34,798	$	39,986	$	10,047	$	9,953	$	10,457	$	1,584	$	1,776	$	1,658	$	1,508	$	1,815	$	1,806
International		38,721		37,402		36,382		21,192		20,572		18,908		3,090		3,246		3,343		2,180		2,227		2,132

Total Exploration and Production		76,050		72,200		76,368		31,239		30,525		29,365		4,674		5,022		5,001		3,688		4,042		3,938

Refining, Marketing and Transportation
United States		12,826		12,959		13,423		5,611		5,881		6,296		482		389		671		490		493		570
International		10,843		11,174		11,194		5,443		5,944		6,310		441		388		411		572		655		530

Total Refining, Marketing and Transportation		23,669		24,133		24,617		11,054		11,825		12,606		923		777		1,082		1,062		1,148		1,100

Chemicals
United States		615		613		614		292		303		317		12		12		16		20		21		21
International		725		719		731		392		404		420		27		24		37		26		38		21

Total Chemicals		1,340		1,332		1,345		684		707		737		39		36		53		46		59		42

All Other⁶
United States		2,877		2,772		2,783		1,466		1,393		1,334		314		169		230		158		109		149
International		18		119		118		15		88		113		2		8		55		3		26		2

Total All Other		2,895		2,891		2,901		1,481		1,481		1,447		316		177		285		161		135		151

Total United States		53,647		51,142		56,806		17,416		17,530		18,404		2,392		2,346		2,575		2,176		2,438		2,546
Total International		50,307		49,414		48,425		27,042		27,008		25,751		3,560		3,666		3,846		2,781		2,946		2,685

Total	$	103,954	$	100,556	$	105,231	$	44,458	$	44,538	$	44,155	$	5,952	$	6,012	$	6,421	$	4,957	$	5,384	$	5,231


¹	Refer to Note 25 on page FS-53 for a discussion of the effect on 2003 PP&E balances and depreciation expenses related to the adoption of FAS 143, “Accounting for Asset Retirement Obligations.”


²	Net of accumulated abandonment and restoration costs of $2,263 at December 31, 2002.


³	Net of dry hole expense related to prior years’ expenditures of $58, $124 and $36 in 2004, 2003 and 2002, respectively.


⁴	Depreciation expense includes accretion expense of $93 and $132 in 2004 and 2003, respectively.


⁵	Depreciation expense includes discontinued operations of $22, $58 and $62 in 2004, 2003 and 2002, respectively.


⁶	Primarily coal, real estate assets and management information systems.

NOTE 16.
ACCOUNTING FOR BUY/SELL CONTRACTS

In January and February 2005, the SEC issued comment letters to ChevronTexaco and other companies in the oil and gas industry requesting disclosure of information related to the accounting for buy/sell contracts. Under a buy/sell contract, a company agrees to buy a specific quantity and quality of a commodity to be delivered at a specific location while simultaneously agreeing to sell a specified quantity and quality of a commodity at a different location to the same counterparty. Physical delivery occurs for each side of the transaction, and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk, and risk of nonperformance by the counterparty. Both parties settle each side of the buy/sell through separate invoicing.

buy/sell arrangements are used to help fulfill the company’s supply agreements to customer locations and specifications.

The company accounts for buy/sell transactions in the Consolidated Statement of Income the same as any other monetary transaction for which title passes, and the risks and rewards of ownership are assumed by the counterparties. At issue with the SEC is whether the industry’s accounting for buy/sell contracts instead should be shown net on the income statement and accounted for under the provisions of Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions” (APB 29).

With regard to the latter, the company’s accounting treatment for buy/sell contracts is based on the view that such

FS-41


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

4 NOTE 16. ACCOUNTING FOR BUY/SELL CONTRACTS – Continued

transactions are monetary in nature. Monetary transactions are outside the scope of APB 29. The company believes its accounting is also supported by the indicators of gross reporting of purchases and sales in paragraph 3 of EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Additionally, FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (FIN 39), prohibits a receivable from being netted against a payable when the receivable is subject to credit risk unless a right of offset exists that is enforceable by law. The company also views netting the separate components of buy/sell contracts in the income statement to be inconsistent with the gross presentation that FIN 39 requires for the resulting receivable and payable on the balance sheet.

As shown on the company’s Consolidated Statement of Income, “Sales and other operating revenues” for the three years ending December 31, 2004, included $18,650, $14,246 and $7,963, respectively, for buy/sell contracts. The costs associated with these buy/sell revenue amounts are included in “Purchased crude oil and products” on the Consolidated Statement of Income in each period.

NOTE 17.
TAXES


	Year ended December 31
	2004			2003		2002

Taxes on income¹
U.S. federal
Current	$	2,246		$	1,133	$	(80	)
Deferred²		(290	)		121		(414	)
State and local		345			133		21

Total United States		2,301			1,387		(473	)

International
Current		5,150			3,864		3,138
Deferred²		66			43		333

Total International		5,216			3,907		3,471

Total taxes on income	$	7,517		$	5,294	$	2,998


¹	Excludes income tax expense of $100, $50 and $26 related to discontinued operations for 2004, 2003 and 2002, respectively.


²	Excludes a U.S. deferred tax benefit of $191 and a foreign deferred tax expense of $170 associated with the adoption of FAS 143 in 2003 and the related cumulative effect of changes in accounting method in 2003.

In 2004, the before-tax income for U.S. operations, including related corporate and other charges, was $7,776, compared with a before-tax income of $5,664 in 2003 and a before-tax loss of $2,162 in 2002. For international operations, before-tax income was $12,775, $7,012 and $6,262 in 2004, 2003 and 2002, respectively. U.S. federal income tax expense was reduced by $176, $196 and $208 in 2004, 2003 and 2002, respectively, for business tax credits.

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
	2004			2003			2002

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		5.3			12.8			29.9
State and local taxes on income, net of U.S. federal income tax benefit		0.9			0.5			1.1
Prior-year tax adjustments		(1.0	)		(1.6	)		(7.1	)
Tax credits		(0.9	)		(1.5	)		(5.1	)
Effects of enacted changes in tax laws		(0.6	)		0.3			2.0
Impairment of investments in equity affiliates		–			–			12.6
Capital loss tax benefit		(2.1	)		(0.8	)		–
Other		–			(1.9	)		–

Consolidated companies		36.6			42.8			68.4
Effect of recording income from certain equity affiliates on an after-tax basis		–			(1.0	)		4.7

Effective tax rate		36.6	%		41.8	%		73.1	%

International taxes in 2004 were reduced by approximately $129 related to changes in income tax laws. 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.

FS-42

4 NOTE 17. TAXES – Continued

The reported deferred tax balances are composed of the following:


	At December 31
	2004			2003*

Deferred tax liabilities
Properties, plant and equipment	$	8,889		$	8,539
Investments and other		931			602

Total deferred tax liabilities		9,820			9,141

Deferred tax assets
Abandonment/environmental reserves		(1,495	)		(1,221	)
Employee benefits		(965	)		(1,272	)
Tax loss carryforwards		(1,155	)		(956	)
Capital losses		(687	)		(264	)
Deferred credits		(838	)		(578	)
Foreign tax credits		(93	)		(352	)
Inventory		(99	)		(57	)
Other accrued liabilities		(300	)		(199	)
Miscellaneous		(876	)		(935	)

Total deferred tax assets		(6,508	)		(5,834	)

Deferred tax assets valuation allowance		1,661			1,553

Total deferred taxes, net	$	4,973		$	4,860


*	2003 conformed to 2004 presentation.

The valuation allowance relates to foreign tax credit carryforwards, tax loss carryforwards and temporary differences for which no benefit is expected to be realized. Tax loss carryforwards exist in many foreign jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from 2005 through 2011. Foreign tax credit carryforwards of $93 will expire in 2014.

At December 31, 2004 and 2003, deferred taxes were classified in the Consolidated Balance Sheet as follows:


	At December 31
	2004			2003

Prepaid expenses and other current assets	$	(1,532	)	$	(940	)
Deferred charges and other assets		(769	)		(641	)
Federal and other taxes on income		6			24
Noncurrent deferred income taxes		7,268			6,417

Total deferred income taxes, net	$	4,973		$	4,860

It is the company’s policy for subsidiaries that are included in the U.S. consolidated tax return to record income tax expense as though they file separately, with the parent recording the adjustment to income tax expense for the effects of consolidation.

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 $10,000 at December 31, 2004. A significant majority of this amount represents earnings reinvested as part of the company’s ongoing international business. It is not practicable to estimate the amount of taxes that might be payable on the eventual remittance of such earnings. The company does not

anticipate incurring additional taxes on remittances of earnings that are not indefinitely reinvested.

American Jobs Creation Act of 2004 In October 2004, the American Jobs Creation Act of 2004 was passed into law. The Act provides a deduction for income from qualified domestic refining and upstream production activities, which will be phased in from 2005 through 2010. For that specific category of income, the company expects the net effect of this provision of the Act to result in a decrease in the federal effective tax rate for 2005 and 2006 to approximately 34 percent, based on current earnings levels. In the long term, the company expects that the new deduction will result in a decrease of the federal effective tax rate to about 32 percent for that category of income, based on current earnings levels.

Taxes other than on income were as follows:


	Year ended December 31
	2004		2003		2002

United States
Excise taxes on products and merchandise	$	4,147	$	3,744	$	3,990
Import duties and other levies		5		11		12
Property and other miscellaneous taxes		359		309		348
Payroll taxes		137		138		141
Taxes on production		257		244		179

Total United States		4,905		4,446		4,670

International
Excise taxes on products and merchandise		3,821		3,351		3,016
Import duties and other levies		10,542		9,652		8,587
Property and other miscellaneous taxes		415		320		291
Payroll taxes		52		54		46
Taxes on production		86		83		79

Total International		14,916		13,460		12,019

Total taxes other than on income*	$	19,821	$	17,906	$	16,689


^*	Includes taxes on discontinued operations of $3, $5, $7 in 2004, 2003 and 2002, respectively.

FS-43


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

NOTE 18.
SHORT-TERM DEBT


	At December 31
	2004			2003

Commercial paper*	$	4,068		$	4,078
Notes payable to banks and others with originating terms of one year or less		310			190
Current maturities of long-term debt		333			863
Current maturities of long-term capital leases		55			71
Redeemable long-term obligations
Long-term debt		487			487
Capital leases		298			299

Subtotal		5,551			5,988
Reclassified to long-term debt		(4,735	)		(4,285	)

Total short-term debt	$	816		$	1,703


*	Weighted-average interest rates at December 31, 2004 and 2003, were 1.98 percent and 1.01 percent, respectively.

Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.

The company periodically enters into interest rate swaps on a portion of its short-term debt. See Note 8 beginning on page FS-35 for information concerning the company’s debt-related derivative activities.

At December 31, 2004, the company had $4,735 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 or bank prime rate. No amounts were outstanding under these credit agreements during 2004 or at year-end.

At December 31, 2004 and 2003, the company classified $4,735 and $4,285, respectively, of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital in 2005, as the company has both the intent and the ability to refinance this debt on a long-term basis.

NOTE 19.
LONG-TERM DEBT

ChevronTexaco has three “shelf” registrations on file with the SEC that together would permit the issuance of $3,800 of debt securities pursuant to Rule 415 of the Securities Act of 1933. The company’s long-term debt outstanding at year-end 2004 and 2003 was as follows:


	At December 31
	2004			2003

3.5% notes due 2007	$	1,995		$	1,993
3.375% notes due 2008		754			749
5.5% note due 2009		422			431
7.327% amortizing notes due 2014¹		360			360
9.75% debentures due 2020		250			250
5.7% notes due 2008		206			220
8.625% debentures due 2031		199			199
8.625% debentures due 2032		199			199
7.5% debentures due 2043		198			198
8.625% debentures due 2010		150			150
8.875% debentures due 2021		150			150
7.09% notes due 2007		144			150
8.25% debentures due 2006		129			150
6.625% notes due 2004		–			499
8.11% amortizing notes due 2004²		–			240
6.0% notes due 2005		–			299
Medium-term notes, maturing from 2017 to 2043 (7.1%)³		210			210
Other foreign currency obligations (4.0%)³		39			52
Other long-term debt (4.3%)³		410			730

Total including debt due within one year		5,815			7,229
Debt due within one year		(333	)		(863	)
Reclassified from short-term debt		4,735			4,285

Total long-term debt	$	10,217		$	10,651


¹	Guarantee of ESOP debt.


²	Debt assumed from ESOP in 1999.


³	Less than $150 individually; weighted-average interest rates at December 31, 2004.

Consolidated long-term debt maturing after December 31, 2004, is as follows: 2005 – $333; 2006 – $149; 2007 – $2,178; 2008 – $1,061; and 2009 – $455; after 2009 – $1,639.

In 2004, the company repaid $500 of 6.625 percent notes and $240 of 8.11 percent notes that matured during the year. Other repayments during 2004 include $300 of 6 percent notes due June 2005 and $265 in various Philippine debt.

In January 2005, the company contributed $98 to permit the ESOP to make a principal payment of $113.

NOTE 20.
NEW ACCOUNTING STANDARDS

FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46) FIN 46 was issued in January 2003 and established standards for determining under what circumstances a variable interest entity (VIE) should be consolidated by 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. In December 2003, the FASB issued FIN 46-R, which not only included amendments to FIN 46, but also required application of the interpretation to all affected entities no later than March 31, 2004, for calendar year- reporting companies. Prior to this requirement, companies were required to apply the interpretation to special-purpose entities by December 31, 2003. The full adoption of the interpretation as of March 31, 2004, including the requirement relating to special-purpose entities, did not have an impact on the company’s results of operations, financial position or liquidity.

FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2). In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became law. The Act

FS-44

4 NOTE 20. NEW ACCOUNTING STANDARDS – Continued

introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB issued FSP FAS 106-2. One U.S. subsidiary was deemed at least actuarially equivalent and eligible for the federal subsidy. The effect on the company’s postretirement benefit obligation and the associated annual expense was de minimis.

FASB Statement No. 151, “Inventory Costs, an Amendment of ARB No. 43, Chapter 4” (FAS 151) In November 2004, the FASB issued FAS 151 which is effective for the company on January 1, 2006. The standard amends the guidance in Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and spoilage. In addition, the standard requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The company is currently evaluating the impact of this standard.

FASB Statement No. 123R, “Share-Based Payment” (FAS 123R) In December 2004, the FASB issued FAS 123R, which requires that compensation costs relating to share-based payments be recognized in the company’s financial statements. The company currently accounts for those payments under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The company is preparing to implement this standard effective July 1, 2005. Although the transition method to be used to adopt the standard has not been selected, the impact of adoption is expected to have a minimal impact on the company’s results of operations, financial position and liquidity. Refer to Note 1, beginning on page FS-30, for the company’s calculation of the pro forma impact on net income of FAS 123, which would be similar to that under FAS 123R.

FASB Statement No. 153, “Exchanges of Nonmonetary Assets, – an Amendment of APB Opinion No. 29,” (FAS 153) In December 2004, the FASB issued FAS 153, which is effective for the company for asset-exchange transactions beginning July 1, 2005. Under APB 29, assets received in certain types of nonmonetary exchanges were permitted to be recorded at the carrying value of the assets that were exchanged (i.e., recorded on a carryover basis). As amended by FAS 153, assets received in some circumstances will have to be recorded instead at their fair values. In the past, ChevronTexaco has not engaged in a large number of nonmon-etary asset exchanges for significant amounts.

NOTE 21.
ACCOUNTING FOR SUSPENDED EXPLORATORY WELLS

Refer to Note 1 on page FS-30 in the section “Properties, Plant and Equipment” for a discussion of the company’s accounting policy for the cost of exploratory wells. The company’s suspended wells are reviewed in this context on a quarterly basis.

The SEC issued comment letters during 2004 and in February 2005 to a number of companies in the oil and gas industry related to the accounting for suspended exploratory wells, particularly for those suspended under certain circumstances for more

than one year. In February 2005, the FASB issued a proposed FSP to amend FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Under the provisions of the draft FSP, exploratory well costs would continue to be capitalized after the completion of drilling when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if an enterprise obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. The FSP provided a number of indicators needing to be present to demonstrate sufficient progress was being made in assessing the reserves and economic viability of the project.

The company will monitor the continuing deliberations of the FASB on this matter and the possible implications, if any, to the company’s accounting policy and the amounts capitalized for suspended-well costs. The disclosures and discussion below address those suggested in the draft FSP and in the additional guidance issued by the SEC in its February 2005 comment letter to companies in the oil and gas industry.

The following table indicates the changes to the company’s suspended exploratory-well costs for the three years ended December 31, 2004:


	Year ended December 31
	2004			2003			2002

Beginning balance at January 1	$	549		$	478		$	655
Additions to capitalized exploratory well costs pending the determination of proved reserves		262			346			209
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(64	)		(145	)		(310	)
Capitalized exploratory well costs charged to expense		(76	)		(128	)		(46	)
Other reductions*		–			(2	)		(30	)

Ending balance at December 31	$	671		$	549		$	478


*	Represents a property sale in 2003 and a retirement due to a legal settlement in 2002.

The following table provides an aging of capitalized well costs, based on the date the drilling was completed, and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:


	Year ended December 31
	2004		2003		2002

Exploratory well costs capitalized for a period of one year or less	$	222	$	181	$	170
Exploratory well costs capitalized for a period greater than one year		449		368		308

Balance at December 31	$	671	$	549	$	478

Number of projects with exploratory well costs that have been capitalized for a period greater than one year*		22		22		27


*	Certain projects have multiple wells or fields or both.

Of the $671 of suspended costs at December 31, 2004, approximately $290 related to 30 wells in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not under way or firmly planned

FS-45


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

4 NOTE 21. ACCOUNTING FOR EXPLORATORY WELLS – Continued

for the near future because the presence of hydrocarbons had already been established and other activities were in process to enable a future decision on project development. The balance related to wells in areas for which drilling was under way or firmly planned for the near future.

Of the $290, approximately $50 related to the well costs suspended one year or less since drilling was completed, and $240 related to costs suspended for more than one year since the completion of drilling. Of the $240 for 11 projects suspended for more than one year since the completion of drilling, activities associated with assessing the reserves and the projects’ economic viability included: (a) $75 – discussions of joint development with an operator in an adjacent field and selection of subsurface and development plans, with front-end-engineering and design (FEED) expected to begin in 2005 (one project); (b) $63 – negotiations with contractors for FEED and negotiations with potential customers for natural gas (two projects); (c) $42 – award of contracts for FEED and finalization of fiscal issues with the host country (one project); (d) $20 - finalization of commercial terms with partners with award of detailed engineering and design contracts expected by the end of 2005 (one project); and (e) $40 – miscellaneous activities for projects with smaller amounts suspended. Progress is being made on all projects in this category; and the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations connected with the projects.

Included in the $449 in the table on the preceding page for year-end 2004 well costs were $42 for four projects and $50 for one project that related to costs suspended in 2000 and 1998, respectively, when drilling in the associated project areas was completed. Certain wells in the project areas may have been suspended prior to these years of last drilling. Other well costs in the $449 total were associated with projects for which drilling was completed since 2000.

If an FSP is implemented similar to the draft issued in February 2005, the company does not believe it would result in

the immediate expensing of a significant amount of suspended-well costs. However, the SEC staff has indicated that it generally would not view conducting environmental and engineering design studies as reasonable support for the suspending of costs beyond one year after drilling is complete. If such restrictions are included in the final FSP, the company may be required to expense a significant amount for wells that had found sufficient hydrocarbons to justify their completion as producing wells and for projects the company continued to consider economically and operationally viable. If a final rule required the company to expense the entire $240 before-tax carrying value for the 11 projects referenced above that were suspended as of December 31, 2004, for more than one year after the completion of drilling, the after-tax charge to earnings would be $150.

NOTE 22.
EMPLOYEE BENEFIT PLANS

The company has defined-benefit pension plans for many employees. The company typically funds only those defined-benefit plans for which funding is required under laws and regulations. In the United States, this includes all qualified tax-exempt plans subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company typically does not fund domestic nonqualified tax-exempt pension plans that are not subject to funding requirements under laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.

The company also sponsors other postretirement plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and the retirees share the costs. In June 2004, the company announced changes to its primary U.S. postretirement benefit plan, which include a limit on future increases in the company contribution, an increase in service points (combination of age and years of company service) required to receive full coverage, and the plan’s prescription drug coverage for retirees becoming secondary to Medicare Part D. Life insurance benefits are paid by the company and annual contributions are based on actual plan experience.

The company uses a measurement date of December 31 to value its pension and other postretirement benefit plan obligations.

FS-46

4 NOTE 22. EMPLOYEE BENEFIT PLANS – Continued

The status of the company’s pension and other postretirement benefit plans for 2004 and 2003 is as follows:


	Pension Benefits
	2004						2003						Other Benefits
	U.S.			Int'l.			U.S.			Int'l.			2004			2003

CHANGE IN BENEFIT OBLIGATION
Benefit obligation at January 1	$	5,819		$	2,708		$	5,308		$	2,163		$	3,135		$	2,865
Service cost		170			70			144			54			26			28
Interest cost		326			180			334			151			164			191
Plan participants’ contributions		1			6			1			1			–			–
Plan amendments		–			26			–			25			(811	)		–
Actuarial loss¹		861			165			708			223			497			244
Foreign currency exchange rate changes		–			207			–			257			8			7
Benefits paid		(590	)		(213	)		(676	)		(162	)		(199	)		(200	)
Curtailment		–			(6	)		–			(4	)		–			–
Special termination benefits		–			1			–			–			–			–

Benefit obligation at December 31		6,587			3,144			5,819			2,708			2,820			3,135

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1		4,444			2,129			3,190			1,645			–			–
Actual return on plan assets		589			229			726			203			–			–
Foreign currency exchange rate changes		–			172			–			228			–			–
Employer contributions		1,332			311			1,203			214			199			200
Plan participants’ contributions		1			6			1			1			–			–
Benefits paid		(590	)		(213	)		(676	)		(162	)		(199	)		(200	)

Fair value of plan assets at December 31		5,776			2,634			4,444			2,129			–			–

FUNDED STATUS		(811	)		(510	)		(1,375	)		(579	)		(2,820	)		(3,135	)
Unrecognized net actuarial loss¹		2,080			939			1,598			918			1,071			646
Unrecognized prior-service cost		308			104			350			92			(771	)		(19	)
Unrecognized net transitional assets		–			7			–			8			–			–

Total recognized at December 31	$	1,577		$	540		$	573		$	439		$	(2,520	)	$	(2,508	)

AMOUNTS RECOGNIZED IN THE CONSOLIDATED BALANCE SHEET AT DECEMBER 31
Prepaid benefit cost	$	1,759		$	933		$	10		$	679		$	–		$	–
Accrued benefit liability²		(712	)		(458	)		(970	)		(392	)		(2,520	)		(2,508	)
Intangible asset		14			5			349			18			–			–
Accumulated other comprehensive income³		516			60			1,184			134			–			–

Net amount recognized	$	1,577		$	540		$	573		$	439		$	(2,520	)	$	(2,508	)


¹	Other benefits in 2003 include a $10 gain for the Medicare Part D federal subsidy for a small subsidiary plan.

The company recorded additional minimum liabilities of $530 and $64 in 2004 for U.S. and international plans, respectively, and $1,533 and $152 in 2003 for U.S. and international plans, respectively, to reflect the amount of unfunded accumulated benefit obligations. The long-term portion of accrued benefits liability is recorded in “Reserves for employee benefit plans,” and the short-term portion is reflected in “Accrued liabilities.”


³	“Accumulated other comprehensive income” includes deferred income taxes of $181 and $21 in 2004 for U.S. and international plans, respectively, and $415 and $47 in 2003 for U.S. and international plans, respectively. This item is presented net of these taxes in the Consolidated Statement of Stockholders’ Equity.

The accumulated benefit obligations for all U.S. and international pension plans were $ 6,117 and $2,734, respectively, at December 31, 2004, and $5,374 and $2,372, respectively, at December 31, 2003.

Information for pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2004 and 2003, was:


	At December 31
	2004		2003

Projected benefit obligations	$	1,449	$	6,637
Accumulated benefit obligations		1,360		6,067
Fair value of plan assets		282		4,791

FS-47


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

4 NOTE 22. EMPLOYEE BENEFIT PLANS – Continued

The components of net periodic benefit cost for 2004, 2003 and 2002 were:


	Pension Benefits
	2004						2003						2002						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2004			2003			2002

Service cost	$	170		$	70		$	144		$	54		$	112		$	47		$	26		$	28		$	25
Interest cost		326			180			334			151			334			143			164			191			178
Expected return on plan assets		(358	)		(169	)		(224	)		(132	)		(288	)		(138	)		–			–			–
Amortization of transitional assets		–			1			–			(3	)		–			(3	)		–			–			–
Amortization of prior-service costs		42			16			45			14			32			12			(47	)		(3	)		(3	)
Recognized actuarial losses (gains)		114			69			133			42			32			27			54			12			(1	)
Settlement losses		96			4			132			1			146			1			–			–			–
Curtailment losses		–			2			–			6			–			–			–			–			–
Special termination benefits recognition		–			1			–			–			–			–			–			–			–

Net periodic benefit cost	$	390		$	174		$	564		$	133		$	368		$	89		$	197		$	228		$	199

Assumptions The following weighted average assumptions were used to determine benefit obligations and net period benefit costs for years ended December 31:


	Pension Benefits
	2004						2003						2002						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2004			2003			2002

Assumptions used to determine benefit obligations Discount rate		5.8	%		6.4	%		6.0	%		6.8	%		6.8	%		7.1	%		5.8	%		6.1	%		6.8	%
Rate of compensation increase		4.0	%		4.9	%		4.0	%		4.9	%		4.0	%		5.5	%		4.1	%		4.1	%		4.1	%
Assumptions used to determine net periodic benefit cost Discount rate*		5.9	%		6.8	%		6.3	%		7.1	%		7.4	%		7.7	%		6.1	%		6.8	%		7.3	%
Expected return on plan assets*		7.8	%		8.3	%		7.8	%		8.3	%		8.3	%		8.9	%		N/A			N/A			N/A
Rate of compensation increase		4.0	%		4.9	%		4.0	%		5.1	%		4.0	%		5.4	%		4.1	%		4.1	%		4.1	%


* Discount rate and expected rate of return on plan assets were reviewed and updated as needed on a quarterly basis for the main U.S. pension plan.

Expected Return on Plan Assets The company employs a rigorous process to determine the estimates of long-term rate of return on pension assets. These estimates are primarily driven by actual historical asset-class returns, an assessment of expected future performance and advice from external actuarial firms while incorporating specific asset class risk factors. Asset allocations are regularly updated using pension plan asset/liability studies, and the determination of the company’s estimates of long-term rates of return are consistent with these studies.

There have been no changes in the expected long-term rate of return on plan assets since 2002 for U.S. plans, which account for about 70 percent of the company’s pension plan assets. At December 31, 2004, the estimated long-term rate of return on U.S. pension plan assets was 7.8 percent.

The year-end market-related value of 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 U.S. accounting rules. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and yet still be contemporaneous to the end of the year. For plans outside the U.S., market value of assets as of the measurement date is used in calculating the pension expense.

Other Benefit Assumptions Effective January 1, 2005, the company amended its main U.S. postretirement medical plan to limit future increases in the company contribution. For current retirees, the increase in company contribution is capped at 4 percent each year. For future retirees, the 4 percent cap will be effective at retirement. Before retirement, the assumed health care cost trend rates start with 10.6 percent in 2004 and gradually drop to 4.8 percent for 2010 and beyond. Once the employee elects to retire, the trend rates are capped at 4 percent.

For the measurement of accumulated postretirement benefit obligation at December 31, 2003, the assumed heath care cost trend rates start with 8.4 percent in 2003 and gradually decline to 4.5 percent for 2007 and beyond.

Assumed health care cost-trend rates have a significant effect on the amounts reported for retiree health care costs. A change of one percentage point in the assumed health care cost-trend rates would have the following effects:

FS-48

4 NOTE 22. EMPLOYEE BENEFIT PLANS – Continued


	1 Percent		1 Percent
	Increase		Decrease

Effect on total service and interest cost components	$	18	$	(15	)
Effect on postretirement benefit obligation	$	86	$	(98	)

Plan Assets and Investment Strategy The company’s pension plan weighted-average asset allocation at December 31 by asset category is as follows:


	U.S.						International
Asset Category	2004			2003			2004			2003

Equities		70	%		70	%		57	%		55	%
Fixed Income		21	%		21	%		42	%		43	%
Real Estate		9	%		8	%		1	%		2	%
Other		–			1	%		–			–

Total		100	%		100	%		100	%		100	%

The pension plans invest primarily in asset categories with sufficient size, liquidity and cost efficiency to permit investments of reasonable size. The pension plans invest in asset categories that provide diversification benefits and are easily measured. To assess the plans’ investment performance, long-term asset allocation policy benchmarks have been established.

For the primary U.S. pension plan, the ChevronTexaco Board of Directors has established the following approved asset allocation ranges: Equities 40-70 percent, Fixed Income 20-65 percent, Real Estate 0-15 percent. The significant international pension plans also have established maximum and minimum asset allocation ranges that vary by each plan. Actual asset allocation within approved ranges is based on a variety of current economic and market conditions and consideration of specific asset category risk.

Equities include investments in the company’s common stock in the amount of $8 and $6 at December 31, 2004 and 2003, respectively. The “Other” asset category includes investments in private equity limited partnerships.

Cash Contributions and benefit Payments In 2004, the company contributed $1,332 and $311 to its U.S. and international pension plans, respectively. In 2005, the company expects contributions to be approximately $250 and $150 to its U.S. and international pension plans, respectively. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

The company anticipates paying other postretirement benefits of approximately $220 in 2005, as compared with $199 in 2004.

The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10 years:


	Pension Benefits				Other
	U.S.		Int’l.		Benefits

2005	$	489	$	144	$	217
2006	$	507	$	150	$	186
2007	$	524	$	160	$	190
2008	$	540	$	171	$	193
2009	$	553	$	180	$	197
2010-2014	$	2,912	$	1,038	$	1,028

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 the ESIP represent the company’s contributions to the plan, which are funded either through the purchase of shares of common stock on the open market or through the release of common stock held in the leveraged employee stock ownership plan (LESOP), which is discussed below. Total company matching contributions to employee accounts within the ESIP were $139, $136 and $136 in 2004, 2003 and 2002, respectively. This cost was reduced by the value of shares released from the LESOP totaling $(138), $(23) and $(73) in 2004, 2003 and 2002, respectively. The remaining amounts, totaling $1, $113 and $63 in 2004, 2003 and 2002, respectively, represent open market purchases.

Employee Stock Ownership Plan Within the ChevronTexaco Employee Savings Investment Plan (ESIP), is an employee stock ownership plan (ESOP). In 1989, Chevron established a leveraged employee stock ownership plan (LESOP) as a constituent part of the ESOP. The LESOP provides partial prefunding of the company’s future commitments to the ESIP.

As permitted by American Institute of Certified Public Accountants (AICPA) Statement of Position 93-6, “Employers’ Accounting for Employee Stock Ownership Plans,” the company has elected to continue its practices, which are based on AICPA 76-3, “Accounting Practices for Certain Employee Stock Ownership Plans,” and subsequent consensus of the EITF of the FASB. The debt of the LESOP is recorded as debt, and shares pledged as collateral are reported as “Deferred compensation and benefit plan trust” 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 and used by the LESOP for debt service. Interest accrued 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.

Total (credits) expenses recorded for the LESOP were $(29), $24 and $98 in 2004, 2003 and 2002, respectively, including $23, $28 and $32 of interest expense related to LESOP debt and a (credit) charge to compensation expense of $(52), $(4) and $66.

Of the dividends paid on the LESOP shares, $52, $61 and $49 were used in 2004, 2003 and 2002, respectively, to service LESOP debt. Included in the 2004 amount was a repayment of debt entered into in 1999 to pay interest on the ESOP debt. Interest expense on this debt was recognized and reported as LESOP interest expense in 1999. In addition, the company made no contributions in 2004 and contributions of $26 and $102 in 2003

FS-49


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

4 NOTE 22. EMPLOYEE BENEFIT PLANS — Continued

and 2002, respectively, to satisfy LESOP debt service in excess of dividends received by the LESOP.

In January 2005, the company contributed $98 to permit the LESOP to make a $144 debt service payment, which included a principal payment of $113.

Shares held in the LESOP are released and allocated to the accounts of plan participants based on debt service deemed to be paid in the year in proportion to the total of current-year and remaining debt service. LESOP shares as of December 31, 2004 and 2003, were as follows:


Thousands	2004		2003

Allocated shares*		24,832		24,198
Unallocated shares		9,940		13,634

Total LESOP shares		34,772		37,832


*	2003 share amounts restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in 2004.

Benefit Plan Trust Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2004, the trust contained 14.2 million shares of ChevronTexaco treasury stock. The company intends to continue to pay its obligations under the benefit plans. The trust will sell the shares or use the dividends from the shares to pay benefits only to the extent that the company does not pay such benefits. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The shares held in the trust are not considered outstanding for earnings-per-share purposes until distributed or sold by the trust in payment of benefit obligations.

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 the recipients 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. Aggregate charges to expense for these management incentive plans, excluding expense related to LTIP and SIP stock options and restricted stock awards that are discussed in Note 23 that follows, were $214, $148 and $48 in 2004, 2003 and 2002, respectively. Included in this amount for 2004 was $14 related to stock appreciation rights.

Other Incentive Plans The company has a program that provides eligible employees, other than those covered by MIP and LTIP, with an annual cash bonus if the company achieves certain financial and safety goals. Charges for the program were $339, $151 and $158 in 2004, 2003 and 2002, respectively.

NOTE 23.
STOCK OPTIONS

The company applies APB Opinion No. 25 and related interpretations in accounting for its stock-based compensation programs. Stock-based compensation expense (credit) recognized in connection with these programs and the stock appreciation rights discussed above was $16, $2 and $(2) in 2004, 2003 and 2002, respectively.

Refer to Note 1 on page FS-30 for the pro forma effects on net income and earnings per share had the company applied the fair-value-recognition provisions of FAS No. 123.

In the discussion below, the references to share price and number of shares have been adjusted for the two-for-one stock split in September 2004, which is discussed in Note 3 on page FS-33.

Broad-Based Employee Stock Options In 1998, Chevron granted to all eligible employees options that varied from 200 to 600 shares of stock or equivalents, dependent on the employee’s salary or job grade. These options vested after two years in February 2000 and expire in February 2008. Options for 9,641,600 shares were awarded at an exercise price of $38.15625 per share. Outstanding option shares were 4,018,350 at the end of 2002. In 2003, exercises of 23,260 and forfeitures of 122,100 reduced the outstanding option shares to 3,872,990 at the end of the year. In 2004, exercises of 1,720,946 and forfeitures of 42,540 reduced the outstanding option shares to 2,109,504 at the end of the year. The company recorded expense (credit) of $2, $2 and $(2) for these options in 2004, 2003 and 2002, respectively.

The fair value of each option share on the date of grant under FAS No. 123 was estimated at $9.54 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, whereas options granted by Texaco under its SIP vested over a two-year period at a rate of 50 percent each year. For a 10-year period after April 2004, no more than 160 million shares may be issued under the Plan, and no more than 64 million of those shares may be in a form other than a stock option, stock appreciation right or award requiring full payment for shares by the award recipient. This provision replaced a formula that restricted annual awards to no more than one percent of shares outstanding at the beginning of each year. Not counted against the 160 million-share maximum are shares issued as a result of the exercise options that were granted before the change in formula in 2004.

On the closing of the merger in October 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

FS-50

4 NOTE 23. STOCK OPTIONS – Continued

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. No amount for these plans was charged to compensation expense in 2004, 2003 or 2002.

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:


	2004			2003			2002

ChevronTexaco plans:
Expected life in years		7			7			7
Risk-free interest rate		4.4	%		3.1	%		4.6	%
Volatility		16.5	%		19.3	%		21.6	%
Dividend yield		3.7	%		3.5	%		3.0	%
Texaco plans:
Expected life in years		2			2			2
Risk-free interest rate		2.5	%		1.7	%		1.6	%
Volatility		17.8	%		22.0	%		24.1	%
Dividend yield		3.8	%		3.9	%		3.1	%

The Black-Scholes weighted-average fair value of the Chevron-Texaco options granted during 2004, 2003 and 2002 was $7.14, $5.51 and $9.30 per share, respectively, and the weighted-average fair value of the SIP restored options granted during 2004, 2003 and 2002 was $4.00, $4.03 and $5.15 per share, respectively.

A summary of the status of stock options awarded under the company’s LTIP, as well as the former Texaco plans, for 2004, 2003 and 2002 follows:


				Weighted- Average
	Options (thousands)			Exercise Price

Outstanding at December 31, 2001		45,240		$	40.57

Granted		6,582			43.07
Exercised		(3,636	)		36.51
Restored		2,548			44.69
Forfeited		(1,490	)		44.05

Outstanding at December 31, 2002		49,244		$	41.33

Granted		9,320			36.70
Exercised		(1,458	)		25.07
Restored		120			41.35
Forfeited		(1,966	)		42.70

Outstanding at December 31, 2003		55,260		$	40.93

Granted		9,164			47.06
Exercised		(14,308	)		39.87
Restored		4,814			48.84
Forfeited		(578	)		43.94

Outstanding at December 31, 2004		54,352		$	42.90

Exercisable at December 31
2002		42,890		$	41.07
2003		42,554		$	41.62
2004		35,547		$	42.15

The following table summarizes information about stock options outstanding, including those from former Texaco plans, at December 31, 2004:


Options Outstanding							Options Exercisable
			Weighted-
			Average		Weighted-				Weighted-
	Number		Remaining		Average		Number		Average
Range of	Outstanding		Contractual		Exercise		Exercisable		Exercise
Exercise Prices	(thousands)		Life (years)		Price		(thousands)		Price

$15 to $25		513		0.55	$	24.09		513	$	24.09
25 to 35		875		1.86		32.94		875		32.94
35 to 45		33,061		6.13		40.97		26,031		41.71
45 to 55		19,846		6.54		47.02		8,128		45.69
55 to 65		57		2.41		55.21		–		–

$15 to $65		54,352		6.15	$	42.90		35,547	$	42.15

NOTE 24.
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 Corporation), 1997 for ChevronTexaco Global Energy Inc. (formerly Caltex) and 1991 for Texaco Inc. 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, 2004, the company and its subsidiaries provided, either directly or indirectly, guarantees of $963 for notes and other contractual obligations of affiliated companies and $130 for third parties, as described by major category below. There are no amounts being carried as liabilities for the company’s obligations under these guarantees.

Of the $963 guarantees provided to affiliates, $774 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 90 percent of the amounts guaranteed will expire by 2009, with the remaining guarantees expiring by the end of 2015. Under the terms of the guarantees, the company would be required to fulfill the guarantee should an affiliate be in default of its loan terms, generally for the full amounts disclosed. There are no recourse provisions, and no assets are held as collateral for these guarantees. The $189 balance of the $963 represents obligations in connection with pricing of power purchase agreements for certain of the company’s 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 $130 have been provided to third parties, including approximately $40 of construction loans to host governments of certain of the company’s international upstream operations. The remaining guarantees of $90 were provided

FS-51


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

4 NOTE 24. OTHER CONTINGENCIES AND COMMITMENTS – Continued

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. About 70 percent of the total amounts guaranteed will expire by 2009. 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 $70 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.

At December 31, 2004, ChevronTexaco also had outstanding guarantees for approximately $215 of Equilon debt and leases. Following the February 2002 disposition of its interest in Equilon, the company received an indemnification from Shell Oil Company for any claims arising from the guarantees. The company has not recorded a liability for these guarantees. Approximately 45 percent of the amounts guaranteed will expire by 2009, with the guarantees of the remaining amounts expiring by 2019.

Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell Oil Company (Shell) and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover certain contingent liabilities, including those associated with the Unocal patent litigation. The company would be required to perform should the indemnified liabilities become actual losses. Should that occur, the company could be required to make future payments up to $300. Through the end of 2004, the company paid approximately $28 under these contingencies and had agreed to pay approximately $10 additional under an award of arbitration, subject to minor adjustments yet to be resolved. The company may receive additional requests for indemnification payments in the future.

Securitization The company securitizes certain retail and trade accounts receivable in its downstream business through the use

of qualifying SPEs. At December 31, 2004, approximately $1,200, representing about 10 percent of ChevronTexaco’s total current accounts receivables balance, were securitized. ChevronTexaco’s total estimated financial exposure under these securitizations at December 31, 2004, was approximately $50. These arrangements have the effect of accelerating ChevronTexaco’s collection of the securitized amounts. In the event that the SPEs experience major defaults in the collection of receivables, ChevronTexaco believes that it would have no loss exposure connected with third-party investments in these securitizations.

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 approximate amounts of required payments under these various commitments are 2005 – $1,600; 2006 – $1,700; 2007 – $1,600; 2008 – $1,500; 2009 – $1,500; 2010 and after – $2,300. Total payments under the agreements were approximately $1,600 in 2004, $1,400 in 2003 and $1,200 in 2002.

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: 2005 – $1,200; 2006 – $1,200; 2007 – $1,300; 2008 – $1,300; and 2009 – $1,300. Additionally, in 2004 the company entered into a 20-year agreement to acquire regasification capacity at the Sabine Pass LNG terminal. Payments of $1,200 over the 20-year period are expected to commence in 2010.

Minority Interests The company has commitments of approximately $172 related to minority interests in subsidiary companies.

Texaco Capital LLC, a wholly owned financial subsidiary, issued Deferred Preferred Shares, Series C, in December 1995. In February 2005, the company redeemed current obligations related to minority interests of approximately $140.

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 federal Superfund sites and analogous sites under state laws, refineries, oil fields, service stations, terminals, and land development areas, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

Although the company has provided for known environmental obligations that are probable and reasonably estimable,

FS-52

4 NOTE 24. OTHER CONTINGENCIES AND COMMITMENTS — Continued

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

ChevronTexaco’s environmental reserve as of December 31, 2004, was $1,047. The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end 2004 had a recorded liability that was material to the company’s financial position, results of operations or liquidity.

Included in the year-end 2004 balance was $107 related to sites for which ChevronTexaco had been identified by the U.S. Environmental Protection Agency or other regulatory agencies under the provisions of the federal Superfund law or analogous state laws as a “potentially responsible party” or otherwise involved in the remediation.

Of the remaining year-end 2004 environmental reserves balance of $940, $712 related to more than 2,000 sites for the company’s U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals) and pipelines. The remaining $228 was associated with various sites in the international downstream ($111), upstream ($69) and chemicals ($48). Liabilities at all sites, whether operating, closed or divested, were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both. These and other activities include one or more of the following: site assessment; soil excavation; offsite disposal of contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid and vapor from soil; groundwater extraction and treatment; and monitoring of the natural attenuation of the contaminants.

Global Operations ChevronTexaco and its affiliates conduct business activities in approximately 180 countries. Areas in which the company and its affiliates have significant operations include the United States, Canada, Australia, the United Kingdom, Norway, Denmark, France, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, Republic of Congo, Angola, Nigeria, Chad, South Africa, Indonesia, the Philippines, Singapore, China, Thailand, Venezuela, Argentina, Brazil, Colombia, Trinidad and Tobago, and South Korea. The company’s CPC affiliate operates in Russia and Kazakhstan. The company’s TCO affiliate operates in Kazakhstan. The company’s CPChem affiliate manufactures and markets a wide range of petrochemicals on a worldwide basis, with manufacturing facilities in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar, Mexico and Belgium.

ownership of the company’s partially or wholly owned businesses or assets or to impose additional taxes or royalties on the company’s operations or both.

In certain locations, 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, acts of violence 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 crude oil and natural gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for 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 remains for a possible net settlement amount for the four zones. ChevronTexaco currently estimates its maximum possible net before-tax liability at approximately $200. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at about $50. The timing of the settlement and the exact amount within this range of estimates were uncertain.

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 take lengthy periods to resolve.

NOTE 25.
FAS 143 — ASSET RETIREMENT OBLIGATIONS

The company adopted Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143), effective January 1, 2003. This accounting standard applies to the fair value of a liability for an asset retirement obligation that is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Obligations associated with the retirement of these assets require recognition in certain circumstances: (1) the present value of a liability and offsetting asset for an ARO, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates. FAS 143 primarily affects the company’s accounting for crude oil and natural gas producing assets and differs in several respects from previous accounting under FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.”

CHEVRONTEXACO CORPORATION 2004 ANNUAL REPORT 53

FS-53


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

4 NOTE 25. FAS 143 – ASSET RETIREMENT OBLIGATIONS – Continued

In the first quarter 2003, the company recorded a net after-tax charge of $200 for the cumulative effect of the adoption of FAS 143, including the company’s share of amounts attributable to equity affiliates. The cumulative-effect adjustment also increased the following balance sheet categories: “Properties, plant and equipment,” $2,568; “Accrued liabilities,” $115; and “Deferred credits and other noncurrent obligations,” $2,674. “Noncurrent deferred income taxes” decreased by $21.

Upon adoption, no significant asset retirement obligations associated with any legal obligations to retire refining, marketing and transportation (downstream) and chemical long-lived assets generally were recognized, as indeterminate settlement dates for the asset retirements prevented estimation of the fair value of the associated ARO. The company performs periodic reviews of its downstream and chemical long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.

Other than the cumulative-effect net charge, the effect of the new accounting standard on net income in 2003 was not materially different from what the result would have been under FAS 19 accounting. Included in “Depreciation, depletion and amortization” were $52 related to the depreciation of the ARO asset and $132 related to the accretion of the ARO liability.

The following table illustrates what the company’s net income before extraordinary items, net income and related per-share amounts would have been if the provisions of FAS 143 had been applied retroactively:


	Year Ended December 31
	2003			2002

Pro forma net income before extraordinary items	$	7,430	¹	$	1,137	²
Earnings per share – basic³	$	3.57		$	0.53
Earnings per share – diluted³	$	3.57		$	0.53
Pro forma net income	$	7,430	¹	$	1,137	²
Earnings per share – basic⁴	$	3.57		$	0.53
Earnings per share – diluted⁴	$	3.57		$	0.53


¹	Excludes cumulative-effect charge of $200 ($0.09 per basic and diluted share) for the adoption of FAS 143.


²	Includes benefit of $5 that represents the reversal of FAS 19 depreciation related to abandonment offset partially by pro forma expenses for the depreciation and accretion of the ARO asset and liability, net of tax. There is a de minimis effect to net income per basic or diluted share.


³	Reported net income before extraordinary items was also $3.57 per basic and diluted


	shares for 2003 and $0.53 per basic and diluted shares for 2002.


⁴	Reported net income was $3.48 per basic and diluted shares for 2003 and $0.53 per basic and diluted shares for 2002.

Prior to the implementation of FAS 143, the company had recorded a provision for abandonment that was part of “Accumulated depreciation, depletion and amortization.” Upon implementation of FAS 143, the provision for abandonment was reversed and ARO liability was recorded. The amount of the abandonment reserve at the end of 2002 was $2,263. The 2002 pro-forma ARO liability at January 1 and December 31 was $2,792 and $2,797, respectively.

The following table indicates the changes to the company’s before-tax asset retirement obligations in 2004 and 2003:


	2004			2003

Balance at January 1	$	2,856		$	2,797	*
Liabilities incurred		37			14
Liabilities settled		(426	)		(128	)
Accretion expense		93			132
Revisions in estimated cash flows		318			41

Balance at December 31	$	2,878		$	2,856


	*Includes the cumulative effect of the accounting change.

NOTE 26.
EARNINGS PER SHARE

Basic earnings per share (EPS) is based upon net income less preferred stock dividend requirements and includes the effects of deferrals of salary and other compensation awards that are invested in ChevronTexaco stock units by certain officers and employees of the company and the company’s share of stock transactions of affiliates, which, under the applicable accounting rules may be recorded directly to the company’s retained earnings instead of net income. Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock

FS-54

4 NOTE 26. EARNINGS PER SHARE – Continued

options awarded under the company’s stock option programs (see Note 23, “Stock Options,” beginning on page FS-50). The following table sets forth the computation of basic and diluted EPS:


	Year ended December 31
	2004		2003			2002

BASIC EPS CALCULATION
Income from continuing operations	$	13,034	$	7,382		$	1,102
Add: Dividend equivalents paid on stock units		3		2			3
Add: Affiliated stock transaction recorded to retained earnings¹		–		170			–

Income from continuing operations available to common stockholders	$	13,037	$	7,554		$	1,105
Income from discontinued operations		294		44			30
Cumulative effect of changes in accounting principle²		–		(196	)		–

Net income available to common stockholders – Basic	$	13,331	$	7,402		$	1,135

Weighted average number of common shares outstanding³		2,114		2,123			2,121
Add: Deferred awards held as stock units		2		2			2

Total weighted average number of common share outstanding		2,116		2,125			2,123

Per-Share of Common Stock
Income from continuing operations available to common stockholders	$	6.16	$	3.55		$	0.52
Income from discontinued operations		0.14		0.02			0.01
Cumulative effect of changes in accounting principle		–		(0.09	)		–

Net income – Basic	$	6.30	$	3.48		$	0.53


DILUTED EPS CALCULATION
Income from continuing operations	$	13,034	$	7,382		$	1,102
Add: Dividend equivalents paid on stock units		3		2			3
Add: Affiliated stock transaction recorded to retained earnings¹		–		170			–
Add: Dilutive effects of employee stock-based awards		1		2			2

Income from continuing operations available to common stockholders	$	13,038	$	7,556		$	1,107
Income from discontinued operations		294		44			30
Cumulative effect of changes in accounting principle²		–		(196	)		–

Net income available to common stockholders – Diluted	$	13,332	$	7,404		$	1,137

Weighted average number of common shares outstanding³		2,114		2,123			2,121
Add: Deferred awards held as stock units		2		2			2
Add: Dilutive effect of employee stock-based awards		6		2			3

Total weighted average number of common share outstanding		2,122		2,127			2,126

Per-Share of Common Stock
Income from continuing operations available to common stockholders	$	6.14	$	3.55		$	0.52
Income from discontinued operations		0.14		0.02			0.01
Cumulative effect of changes in accounting principle		–		(0.09	)		–

Net income – Diluted	$	6.28	$	3.48		$	0.53


¹	2003 amount is the company’s share of a capital stock transaction of its Dynegy affiliate, which, under the applicable accounting rules, was recorded directly to retained earnings.


²	Includes a net loss of $200 for the adoption of FAS 143 and a net gain of $4 for the company’s share of Dynegy’s cumulative effect of adoption of EITF 02-3.


³	Share amounts in all period reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.

FS-55

(This page intentionally left blank.)

FS-56


	Five-Year Financial Summary

Unaudited


Millions of dollars, except per-share amounts	2004		2003			2002		2001			2000

COMBINED STATEMENT OF INCOME DATA
REVENUES AND OTHER INCOME
Total sales and other operating revenues	$	150,865	$	119,575		$	98,340	$	103,951		$	116,619
Income from equity affiliates and other income		4,435		1,702			197		1,751			1,917

TOTAL REVENUES AND OTHER INCOME		155,300		121,277			98,537		105,702			118,536
TOTAL COSTS AND OTHER DEDUCTIONS		134,749		108,601			94,437		97,517			104,661

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		20,551		12,676			4,100		8,185			13,875
INCOME TAX EXPENSE		7,517		5,294			2,998		4,310			6,237

NET INCOME FROM CONTINUING OPERATIONS		13,034		7,382			1,102		3,875			7,638
NET INCOME FROM DISCONTINUED OPERATIONS		294		44			30		56			89

NET INCOME BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES		13,328		7,426			1,132		3,931			7,727
Extraordinary loss, net of tax		–		–			–		(643	)		–
Cumulative effect of changes in accounting principles		–		(196	)		–		–			–

NET INCOME	$	13,328	$	7,230		$	1,132	$	3,288		$	7,727

PER SHARE OF COMMON STOCK¹
INCOME FROM CONTINUING OPERATIONS²
– Basic	$	6.16	$	3.55		$	0.52	$	1.82		$	3.58
– Diluted	$	6.14	$	3.55		$	0.52	$	1.82		$	3.57
INCOME FROM DISCONTINUED OPERATIONS
– Basic	$	0.14	$	0.02		$	0.01	$	0.03		$	0.04
– Diluted	$	0.14	$	0.02		$	0.01	$	0.03		$	0.04
EXTRAORDINARY ITEM
– Basic	$	–	$	–		$	–	$	(0.30	)	$	–
– Diluted	$	–	$	–		$	–	$	(0.30	)	$	–
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
– Basic	$	–	$	(0.09	)	$	–	$	–		$	–
– Diluted	$	–	$	(0.09	)	$	–	$	–		$	–
NET INCOME²
– Basic	$	6.30	$	3.48		$	0.53	$	1.55		$	3.62
– Diluted	$	6.28	$	3.48		$	0.53	$	1.55		$	3.61

CASH DIVIDENDS PER SHARE³	$	1.53	$	1.43		$	1.40	$	1.33		$	1.30

COMBINED BALANCE SHEET DATA (AT DECEMBER 31)
Current assets	$	28,503	$	19,426		$	17,776	$	18,327		$	17,913
Noncurrent assets		64,705		62,044			59,583		59,245			59,708

TOTAL ASSETS		93,208		81,470			77,359		77,572			77,621

Short-term debt		816		1,703			5,358		8,429			3,094
Other current liabilities		17,979		14,408			14,518		12,225			13,567
Long-term debt and capital lease obligations		10,456		10,894			10,911		8,989			12,821
Other noncurrent liabilities		18,727		18,170			14,968		13,971			14,770

TOTAL LIABILITIES		47,978		45,175			45,755		43,614			44,252

STOCKHOLDERS’ EQUITY	$	45,230	$	36,295		$	31,604	$	33,958		$	33,369


¹	Per-share amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.


²	The amount in 2003 includes a benefit of $0.08 for the company’s share of a capital stock transaction of its Dynegy Inc. affiliate, which, under the applicable accounting rules, was recorded directly to retained earnings and not included in net income for the period.


³	Chevron Corporation dividend pre-merger.


	Supplemental Information on Oil and Gas Producing Activities

Unaudited

In accordance with Statement of FAS 69, “Disclosures About Oil and Gas Producing Activities,” this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized

costs; and results of operations. Tables V through VII present information on the company’s estimated net proved reserve quantities; standardized measure of estimated discounted future net cash flows related to proved reserves;

FS-57


	Supplemental Information on Oil and Gas Producing Activities – Continued

and changes in estimated discounted future net cash flows. The Africa geographic area includes activities principally in Nigeria, Angola, Chad, Republic of Congo and the Democratic Republic of the Congo (sold in 2004). The Asia-Pacific geographic area includes activities principally in Australia, China, Kazakhstan, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, Papua New Guinea (sold in 2003), the Philippines, and Thailand. The international “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 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.

Amounts in the tables exclude the cumulative effect adjustment for the adoption of FAS 143, “Asset Retirement Obligations.” Refer to Note 25 on page FS-53.

TABLE I – COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS AND DEVELOPMENT¹


	Consolidated Companies
	United States									International
			Gulf of					Total				Asia-						Total				Affiliated Companies
Millions of dollars	Calif.		Mexico		Other			U.S.		Africa		Pacific		Indonesia		Other		Int’l.		Total		TCO		Hamaca

YEAR ENDED DEC. 31, 2004
Exploration
Wells	$	–	$	388	$	–		$	388	$	116	$	25	$	2	$	127	$	270	$	658	$	–	$	–
Geological and geophysical		–		47		2			49		103		10		12		46		171		220		–		–
Rentals and other		–		43		3			46		52		47		1		53		153		199		–		–

Total exploration		–		478		5			483		271		82		15		226		594		1,077		–		–

Property acquisitions
Proved²		–		6		1			7		111		16		–		4		131		138		–		–
Unproved		–		29		–			29		82		–		–		5		87		116		–		–

Total property acquisitions		–		35		1			36		193		16		–		9		218		254		–		–

Development³		412		457		372			1,241		1,047		567		245		542		2,401		3,642		896		208
ARO Asset		1		9		3			13		10		53		158		85		306		319		–		–

TOTAL COSTS INCURRED	$	413	$	979	$	381		$	1,773	$	1,521	$	718	$	418	$	862	$	3,519	$	5,292	$	896	$	208

YEAR ENDED DEC. 31, 2003
Exploration
Wells	$	–	$	415	$	9		$	424	$	116	$	43	$	2	$	72	$	233	$	657	$	–	$	–
Geological and geophysical		–		16		23			39		75		9		5		30		119		158		–		–
Rentals and other		–		64		(20	)		44		12		58		–		46		116		160		–		–

Total exploration		–		495		12			507		203		110		7		148		468		975		–		–

Property acquisitions
Proved²		–		15		3			18		–		20		–		7		27		45		–		–
Unproved		–		30		3			33		51		6		–		14		71		104		–		–

Total property acquisitions		–		45		6			51		51		26		–		21		98		149		–		–

Development		264		434		350			1,048		974		605		363		461		2,403		3,451		551		199

TOTAL COSTS INCURRED	$	264	$	974	$	368		$	1,606	$	1,228	$	741	$	370	$	630	$	2,969	$	4,575	$	551	$	199

YEAR ENDED DEC. 31, 2002
Exploration
Wells	$	25	$	413	$	39		$	477	$	131	$	32	$	16	$	92	$	271	$	748	$	–	$	–
Geological and geophysical		–		86		9			95		69		30		13		53		165		260		–		–
Rentals and other		–		30		5			35		29		37		1		43		110		145		–		–

Total exploration		25		529		53			607		229		99		30		188		546		1,153		–		–

Property acquisitions
Proved²		–		96		10			106		–		–		–		–		–		106		–		–
Unproved		–		48		3			51		6		2		–		1		9		60		–		–

Total property acquisitions		–		144		13			157		6		2		–		1		9		166		–		–

Development		221		475		395			1,091		661		593		424		926		2,604		3,695		447		353

TOTAL COSTS INCURRED	$	246	$	1,148	$	461		$	1,855	$	896	$	694	$	454	$	1,115	$	3,159	$	5,014	$	447	$	353


¹	Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. See Note 25, FAS 143, “Asset Retirement Obligations,” on page FS-53.


²	Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired through property exchanges.


³	Includes $63 costs incurred prior to assignment of proved reserves.

FS-58

TABLE II – CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES¹


	Consolidated Companies
	United States								International
			Gulf of				Total				Asia-						Total				Affiliated Companies
Millions of dollars	Calif.		Mexico		Other		U.S.		Africa		Pacific		Indonesia		Other		Int'l.		Total		TCO		Hamaca

AT DEC. 31, 2004
Unproved properties	$	769	$	380	$	109	$	1,258	$	322	$	211	$	–	$	970	$	1,503	$	2,761	$	108	$	–
Proved properties and related producing assets		9,170		16,610		8,660		34,440		7,188		7,485		3,643		8,961		27,277		61,717		2,163		963
Support equipment		211		175		208		594		513		127		3,030		361		4,031		4,625		496		–
Deferred exploratory wells		–		225		–		225		213		81		–		152		446		671		–		–
Other uncompleted projects		91		400		169		660		2,050		605		351		391		3,397		4,057		1,749		149
ARO asset²		28		204		70		302		206		113		181		292		792		1,094		20		–

GROSS CAP. COSTS		10,269		17,994		9,216		37,479		10,492		8,622		7,205		11,127		37,446		74,925		4,536		1,112

Unproved properties valuation		734		111		27		872		118		67		–		294		479		1,351		15		–
Proved producing properties – Depreciation and depletion		6,694		13,562		5,617		25,873		3,753		3,122		2,396		4,933		14,204		40,077		423		43
Support equipment depreciation		148		107		139		394		268		60		1,802		206		2,336		2,730		190		–
ARO asset depreciation²		24		174		64		262		128		49		36		148		361		623		5		–

Accumulated provisions		7,600		13,954		5,847		27,401		4,267		3,298		4,234		5,581		17,380		44,781		633		43

NET CAPITALIZED COSTS	$	2,669	$	4,040	$	3,369	$	10,078	$	6,225	$	5,324	$	2,971	$	5,546	$	20,066	$	30,144	$	3,903	$	1,069

AT DEC. 31, 2003³
Unproved properties	$	769	$	416	$	131	$	1,316	$	290	$	214	$	–	$	1,048	$	1,552	$	2,868	$	108	$	–
Proved properties and related producing assets		8,785		18,069		10,749		37,603		6,474		6,288		3,097		10,469		26,328		63,931		2,091		356
Support equipment		200		200		277		677		519		100		3,016		374		4,009		4,686		425		–
Deferred exploratory wells		–		126		1		127		233		67		2		120		422		549		–		–
Other uncompleted projects		76		280		152		508		1,894		1,502		715		334		4,445		4,953		1,011		661
ARO asset²		25		227		83		335		207		60		23		236		526		861		20		1

GROSS CAP. COSTS		9,855		19,318		11,393		40,566		9,617		8,231		6,853		12,581		37,282		77,848		3,655		1,018

Unproved properties valuation		731		138		43		912		101		59		1		310		471		1,383		12		–
Proved producing properties – depreciation and depletion		6,473		14,450		6,894		27,817		3,656		2,793		2,022		6,015		14,486		42,303		354		24
Support equipment depreciation		141		133		180		454		237		68		1,784		200		2,289		2,743		160		–
ARO asset depreciation²		23		186		79		288		133		36		19		148		336		624		4		–

Accumulated provisions		7,368		14,907		7,196		29,471		4,127		2,956		3,826		6,673		17,582		47,053		530		24

NET CAPITALIZED COSTS	$	2,487	$	4,411	$	4,197	$	11,095	$	5,490	$	5,275	$	3,027	$	5,908	$	19,700	$	30,795	$	3,125	$	994


¹	Includes assets held for sale.


²	See Note 25, FAS 143, “Asset Retirement Obligations,” on page FS-53


³	2003 and 2002 reclassified to conform to 2004 presentation.

FS-59


	Supplemental Information on Oil and Gas Producing Activities – Continued

TABLE II – CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES¹ – Continued


	Consolidated Companies
	United States								International
			Gulf of				Total				Asia-						Total				Affiliated Companies
Millions of dollars	Calif.		Mexico		Other		U.S.		Africa		Pacific		Indonesia		Other		Int'l.		Total		TCO		Hamaca

AT DEC. 31, 2002²
Unproved properties	$	770	$	421	$	171	$	1,362	$	330	$	237	$	22	$	1,134	$	1,723	$	3,085	$	108	$	–
Proved properties and related producing assets		8,584		17,657		11,200		37,441		6,037		6,356		3,432		10,185		26,010		63,451		1,975		147
Support equipment		187		189		398		774		447		190		3,004		377		4,018		4,792		338		–
Deferred exploratory wells		–		101		1		102		167		103		–		106		376		478		–		–
Other uncompleted projects		97		209		200		506		1,380		1,179		474		264		3,297		3,803		676		693

GROSS CAP. COSTS		9,638		18,577		11,970		40,185		8,361		8,065		6,932		12,066		35,424		75,609		3,097		840

Unproved properties valuation		732		154		75		961		80		67		23		277		447		1,408		9		–
Proved producing properties – depreciation and depletion		6,295		13,722		7,098		27,115		3,275		2,608		2,143		5,358		13,384		40,499		285		9
Future abandonment and restoration		150		363		486		999		508		147		157		392		1,204		2,203		24		–
Support equipment depreciation		130		123		304		557		289		100		1,764		223		2,376		2,933		138		–

Accumulated provisions		7,307		14,362		7,963		29,632		4,152		2,922		4,087		6,250		17,411		47,043		456		9

NET CAPITALIZED COSTS	$	2,331	$	4,215	$	4,007	$	10,553	$	4,209	$	5,143	$	2,845	$	5,816	$	18,013	$	28,566	$	2,641	$	831


¹	Includes assets held for sale.


²	2003 and 2002 reclassified to conform to 2004 presentation.

FS-60

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 2004, 2003 and 2002 are shown in the following table. Net income from exploration and production activities as reported on page FS-36 reflects income taxes computed on an effective rate basis. In accordance with FAS 69,

income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the net income amounts on page FS-36.


	Consolidated Companies
	United States												International
				Gulf of						Total						Asia-									Total						Affiliated Companies
Millions of dollars	Calif.			Mexico			Other			U.S.			Africa			Pacific			Indonesia			Other			Int’l.			Total			TCO			Hamaca

YEAR ENDED DEC. 31, 2004
Revenues from net production
Sales	$	251		$	1,925		$	2,163		$	4,339		$	1,321		$	1,191		$	256		$	2,481		$	5,249		$	9,588		$	1,619		$	205
Transfers		2,651			1,768			1,224			5,643			2,645			2,265			1,613			1,903			8,426			14,069			–			–

Total		2,902			3,693			3,387			9,982			3,966			3,456			1,869			4,384			13,675			23,657			1,619			205
Production expenses excluding taxes		(710	)		(547	)		(697	)		(1,954	)		(574	)		(431	)		(591	)		(544	)		(2,140	)		(4,094	)		(143	)		(53	)
Taxes other than on income		(57	)		(45	)		(321	)		(423	)		(24	)		(138	)		(1	)		(134	)		(297	)		(720	)		(26	)		–
Proved producing properties:
depreciation and depletion		(232	)		(774	)		(384	)		(1,390	)		(367	)		(401	)		(393	)		(798	)		(1,959	)		(3,349	)		(104	)		(4	)
Accretion expense²		(12	)		(25	)		(19	)		(56	)		(22	)		(8	)		(13	)		11			(32	)		(88	)		(2	)		–
Exploration expenses		–			(227	)		(6	)		(233	)		(235	)		(69	)		(17	)		(144	)		(465	)		(698	)		–			–
Unproved properties valuation		(3	)		(29	)		(4	)		(36	)		(23	)		(8	)		–			(25	)		(56	)		(92	)		–			–
Other (expense) income³		14			24			474			512			49			10			12			1,028			1,099			1,611			(7	)		(58	)

Results before income taxes		1,902			2,070			2,430			6,402			2,770			2,411			866			3,778			9,825			16,227			1,337			90
Income tax expense		(703	)		(765	)		(898	)		(2,366	)		(2,036	)		(1,395	)		(371	)		(1,759	)		(5,561	)		(7,927	)		(401	)		–

RESULTS OF PRODUCING OPERATIONS	$	1,199		$	1,305		$	1,532		$	4,036		$	734		$	1,016		$	495		$	2,019		$	4,264		$	8,300		$	936		$	90

YEAR ENDED DEC. 31, 2003⁴
Revenues from net production
Sales	$	261		$	2,197		$	2,049		$	4,507		$	1,339		$	1,442		$	55		$	2,556		$	5,392		$	9,899		$	1,116		$	104
Transfers		2,085			1,740			1,096			4,921			1,835			1,738			1,566			1,356			6,495			11,416			–			–

Total		2,346			3,937			3,145			9,428			3,174			3,180			1,621			3,912			11,887			21,315			1,116			104
Production expenses excluding taxes		(631	)		(578	)		(750	)		(1,959	)		(505	)		(331	)		(616	)		(669	)		(2,121	)		(4,080	)		(117	)		(20	)
Taxes other than on income		(28	)		(48	)		(280	)		(356	)		(22	)		(126	)		(1	)		(100	)		(249	)		(605	)		(29	)		–
Proved producing properties:
depreciation and depletion		(224	)		(878	)		(430	)		(1,532	)		(327	)		(398	)		(314	)		(846	)		(1,885	)		(3,417	)		(97	)		(4	)
Accretion expense²		(12	)		(37	)		(20	)		(69	)		(20	)		(5	)		(8	)		(26	)		(59	)		(128	)		(2	)		–
Exploration expenses		(2	)		(168	)		(23	)		(193	)		(123	)		(130	)		(8	)		(117	)		(378	)		(571	)		–			–
Unproved properties valuation		–			(16	)		(4	)		(20	)		(20	)		(9	)		–			(41	)		(70	)		(90	)		–			–
Other (expense) income³		(18	)		(104	)		(51	)		(173	)		(173	)		(342	)		2			(175	)		(688	)		(861	)		(4	)		(35	)

Results before income taxes		1,431			2,108			1,587			5,126			1,984			1,839			676			1,938			6,437			11,563			867			45
Income tax expense		(528	)		(777	)		(585	)		(1,890	)		(1,410	)		(1,158	)		(289	)		(831	)		(3,688	)		(5,578	)		(260	)		–

RESULTS OF PRODUCING OPERATIONS	$	903		$	1,331		$	1,002		$	3,236		$	574		$	681		$	387		$	1,107		$	2,749		$	5,985		$	607		$	45


¹	The value of owned production consumed on lease 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	See Note 25 on page FS-53, FAS 143, “Asset Retirement Obligations.”

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 MD&A on pages FS-6 through FS-8.


⁴	2003 includes certain reclassifications to conform to 2004 presentation.

FS-61


	Supplemental Information on Oil and Gas Producing Activities – Continued

TABLE III – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES¹ – Continued


	Consolidated Companies
	United States												International
				Gulf of						Total						Asia-									Total						Affiliated Companies
Millions of dollars	Calif.			Mexico			Other			U.S.			Africa			Pacific			Indonesia			Other			Int’l.			Total			TCO			Hamaca

YEAR ENDED DEC. 31, 2002²
Revenues from net production
Sales	$	359		$	1,302		$	1,076		$	2,737		$	1,121		$	1,181		$	229		$	2,080		$	4,611		$	7,348		$	955		$	44
Transfers		1,621			1,611			1,193			4,425			1,663			1,560			1,530			1,202			5,955			10,380			–			–

Total		1,980			2,913			2,269			7,162			2,784			2,741			1,759			3,282			10,566			17,728			955			44
Production expenses excluding taxes		(570	)		(630	)		(782	)		(1,982	)		(415	)		(330	)		(680	)		(606	)		(2,031	)		(4,013	)		(130	)		(4	)
Taxes other than on income		(60	)		(53	)		(226	)		(339	)		(24	)		(114	)		–			(77	)		(215	)		(554	)		(36	)		–
Proved producing properties:
depreciation and depletion		(250	)		(844	)		(389	)		(1,483	)		(314	)		(345	)		(315	)		(654	)		(1,628	)		(3,111	)		(86	)		(5	)
FAS 19 abandonment provision³		(12	)		(70	)		(12	)		(94	)		(38	)		(16	)		3			(40	)		(91	)		(185	)		(5	)		–
Exploration expenses		1			(179	)		(38	)		(216	)		(106	)		(89	)		(20	)		(160	)		(375	)		(591	)		–			–
Unproved properties valuation		(2	)		(24	)		(9	)		(35	)		(14	)		(9	)		–			(67	)		(90	)		(125	)		–			–
Other (expense) income⁴		(58	)		(108	)		(193	)		(359	)		(179	)		(202	)		(31	)		59			(353	)		(712	)		(5	)		(12	)

Results before income taxes		1,029			1,005			620			2,654			1,694			1,636			716			1,737			5,783			8,437			693			23
Income tax expense		(362	)		(353	)		(218	)		(933	)		(1,202	)		(1,097	)		(337	)		(677	)		(3,313	)		(4,246	)		(208	)		–

RESULTS OF PRODUCING OPERATIONS	$	667		$	652		$	402		$	1,721		$	492		$	539		$	379		$	1,060		$	2,470		$	4,191		$	485		$	23


¹	The value of owned production consumed on lease 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	2002 includes certain reclassifications to conform to 2004 presentation.


³	See Note 25 on page FS-53, FAS 143, “Asset Retirement Obligations.”

⁴

TABLE IV – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES – UNIT PRICES AND COSTS^1,2


	Consolidated Companies
	United States								International
			Gulf of				Total				Asia-						Total				Affiliated Companies
	Calif.		Mexico		Other		U.S.		Africa		Pacific		Indonesia		Other		Int’l.		Total		TCO		Hamaca

YEAR ENDED DEC. 31, 2004
Average sales prices
Liquids, per barrel	$	33.43	$	34.69	$	34.61	$	34.12	$	34.85	$	31.34	$	31.12	$	34.58	$	33.33	$	33.60	$	30.23	$	23.32
Natural gas, per thousand cubic feet		5.18		6.08		5.07		5.51		0.04		3.41		3.88		2.68		2.90		4.27		0.65		0.27
Average production costs, per barrel		8.14		5.26		6.65		6.60		4.89		3.50		9.69		3.47		4.67		5.43		2.31		6.10

YEAR ENDED DEC. 31, 2003
Average sales prices
Liquids, per barrel	$	25.77	$	27.89	$	26.48	$	26.66	$	28.54	$	24.66	$	25.10	$	27.56	$	26.70	$	26.69	$	22.07	$	17.06
Natural gas, per thousand cubic feet		5.04		5.56		4.51		5.01		0.04		3.64		2.26		2.58		2.87		4.08		0.68		0.33
Average production costs, per barrel		7.01		4.47		6.40		5.82		4.42		2.49		9.30		3.99		4.41		4.99		2.04		3.24

YEAR ENDED DEC. 31, 2002
Average sales prices
Liquids, per barrel	$	20.75	$	22.22	$	21.13	$	21.34	$	24.33	$	21.52	$	22.07	$	23.31	$	22.92	$	22.36	$	18.16	$	18.91
Natural gas, per thousand cubic feet		2.98		3.19		2.60		2.89		0.04		3.11		0.84		2.11		2.24		2.62		0.57		–
Average production costs, per barrel³		5.91		4.49		6.24		5.48		3.49		2.50		7.94		3.59		4.03		4.63		2.19		1.58


¹	The value of owned production consumed on lease as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.


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


³	Conformed to 2004 presentation to exclude taxes.

FS-62

TABLE V – RESERVE QUANTITY INFORMATION

Reserves Governance The company has adopted a comprehensive reserves and resource classification system modeled after a system developed and approved by the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. The system classifies recoverable hydrocarbons into six categories, three deemed commercial and three noncommercial. Within the commercial classification are proved reserves and two categories of unproved, probable and possible. The noncommercial categories are also referred to as contingent resources. For reserves estimates to be classified as proved they must meet all SEC standards and demonstrate a high probability of being produced.

Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.

Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves do not include additional quantities that may eventually result from extensions of currently proved areas or from applying the secondary or tertiary recovery processes not yet tested and determined to be economic.

Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change as additional information becomes available.

Proved reserves are estimated by company asset teams composed of earth scientists and reservoir engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the corporate reserves manager, who is a member of a corporate department that reports directly to the executive vice president responsible for the company’s worldwide exploration and production activities. All of the RAC members are knowledgeable of SEC guidelines for proved reserves classification. The RAC coordinates its activities through two operating company-level reserves managers. These two reserves managers are not members of the RAC so as to preserve the corporate-level independence.

The RAC has the following primary responsibilities: provide independent reviews of the business units’ recommended reserve changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve volumes are calculated using consistent and appropriate standards, procedures and technology; and maintain the Corporate Reserves Manual, which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.

During the year, the RAC is represented in meetings with each of the company’s upstream business units to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company’s Strategy and Planning Committee, whose members include the Chief Executive Officer and the Chief Financial Officer. The company’s annual reserve activity is also presented to and discussed with

the Board of Directors. Other major reserves-related issues are discussed with the Board as necessary throughout the year.

RAC subteams also conduct in-depth reviews during the year of many of the fields that have the largest proved reserves quantities. These reviews include an examination of the proved reserve records and documentation of their alignment with the Corporate Reserves Manual.

Reserve Quantities At December 31, 2004, total oil-equivalent reserves for the company’s consolidated operations were 8.2 billion barrels. (Refer to page E-12 for the definition of oil-equivalent reserves.) Nearly 30 percent were in the United States and about 10 percent in Indonesia. For the company’s interests in equity affiliates, oil-equivalent reserves were 3.1 billion barrels, nearly 85 percent of which were associated with the company’s 50 percent ownership in TCO. Fewer than 20 other individual properties in the company’s portfolio of assets each contained between 1 percent and 4 percent of the company’s oil-equivalent proved reserves, which in the aggregate accounted for about 35 percent of the company’s proved reserves total. These other properties were geographically dispersed, located in the United States, South America, Europe, West Africa, the Middle East and the Asia-Pacific region.

In the United States, total oil-equivalent reserves at year-end 2004 were 2.4 billion barrels. Of this amount, 45 percent, 20 percent and 35 percent were located in California, the Gulf of Mexico and other U.S. areas, respectively.

In California, liquids reserves represented 95 percent of the total, with most classified as heavy oil. Because of heavy oil’s high viscosity and the need to employ enhanced recovery methods, the producing operations are capital intensive in nature. Most of the company’s heavy-oil fields in California employ a continuous steamflooding process.

In the Gulf of Mexico region, liquids represented approximately 60 percent of total oil-equivalent reserves. Production operations are mostly offshore and, as a result, are also capital intensive. Costs include investments in wells, production platforms and other facilities, such as gathering lines and storage facilities.

In other U.S. areas, the reserves were split about equally between liquids and natural gas. For production of crude oil, some fields utilize enhanced recovery methods, including water-flood and CO₂ injection.

ChevronTexaco operates the Boscan Field in Venezuela under a service agreement, but has not recorded reserve quantities for this operation.

The pattern of net reserve changes shown in the following tables, for the three years ending December 31, 2004, is not necessarily indicative of future trends. The company’s ability to add proved reserves is affected by, among other things, matters that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, declines in oil and gas prices, OPEC constraints, geopolitical uncertainties and civil unrest.

The company’s estimated net proved underground oil and natural gas reserves and changes thereto for the years 2002, 2003 and 2004 are shown in the following tables.

FS-63


	Supplemental Information on Oil and Gas Producing Activities – Continued

TABLE V – RESERVE QUANTITY INFORMATION – Continued

NET PROVED RESERVES OF CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS


	Consolidated Companies
	United States												International
				Gulf of						Total						Asia-									Total						Affiliated Companies
Millions of dollars	Calif.			Mexico			Other			U.S.			Africa			Pacific			Indonesia			Other			Int’l.			Total			TCO			Hamaca

RESERVES AT JAN. 1, 2002		1,140			458			703			2,301			1,544			792			1,114			745			4,195			6,496			1,541			487
Changes attributable to:
Revisions		(33	)		(45	)		(38	)		(116	)		164			41			(155	)		17			67			(49	)		199			–
Improved recovery		81			10			8			99			82			–			22			36			140			239			–			–
Extensions and discoveries		3			38			7			48			301			81			4			8			394			442			–			–
Purchases¹		–			2			6			8			–			–			–			–			–			8			–			–
Sales²		–			–			(3	)		(3	)		–			–			–			–			–			(3	)		–			–
Production		(89	)		(74	)		(57	)		(220	)		(115	)		(99	)		(96	)		(109	)		(419	)		(639	)		(51	)		(2	)

RESERVES AT DEC. 31, 2002		1,102			389			626			2,117			1,976			815			889			697			4,377			6,494			1,689			485
Changes attributable to:
Revisions		(4	)		(5	)		–			(9	)		(1	)		105			(57	)		19			66			57			200			–
Improved recovery		38			8			7			53			36			–			54			52			142			195			–			–
Extensions and discoveries		2			113			9			124			24			15			3			26			68			192			–			–
Purchases¹		–			1			–			1			–			–			–			12			12			13			–			–
Sales²		(3	)		(2	)		(18	)		(23	)		–			(42	)		–			(1	)		(43	)		(66	)		–			–
Production		(84	)		(69	)		(52	)		(205	)		(112	)		(97	)		(82	)		(109	)		(400	)		(605	)		(49	)		(6	)

RESERVES AT DEC. 31, 2003		1,051			435			572			2,058			1,923			796			807			696			4,222			6,280			1,840			479
Changes attributable to:
Revisions		13			(68	)		(2	)		(57	)		(70	)		(43	)		(36	)		(12	)		(161	)		(218	)		206			(2	)
Improved recovery		28			–			6			34			34			–			6			–			40			74			–			–
Extensions and discoveries		–			8			6			14			77			9			–			17			103			117			–			–
Purchases¹		–			2			–			2			–			–			–			–			–			2			–			–
Sales²		–			(27	)		(103	)		(130	)		(16	)		–			–			(33	)		(49	)		(179	)		–			–
Production		(81	)		(56	)		(47	)		(184	)		(115	)		(86	)		(79	)		(101	)		(381	)		(565	)		(52	)		(9	)

RESERVES AT DEC. 31, 2004³		1,011			294			432			1,737			1,833			676			698			567			3,774			5,511			1,994			468

DEVELOPED RESERVES⁴

At Jan. 1, 2002		885			393			609			1,887			923			648			843			517			2,931			4,818			1,007			38
At Dec. 31, 2002		867			335			564			1,766			1,042			642			655			529			2,868			4,634			99			63
At Dec. 31, 2003		832			304			515			1,651			1,059			641			588			522			2,810			4,461			1,304			140
At Dec. 31, 2004		832			192			386			1,410			990			543			490			469			2,492			3,902			1,510			188


¹	Includes reserves acquired through property exchanges.


²	Includes reserves disposed of through property exchanges.


³	Net reserve changes (excluding production) in 2004 consist of 5 million barrels of developed reserves and (209) million barrels of undeveloped reserves for consolidated companies and 315 million barrels of developed reserves and (111) million barrels of undeveloped reserves for affiliated companies.


⁴	During 2004, the percentages of undeveloped reserves at December 31, 2003, transferred to developed reserves were 13 percent and 15 percent for consolidated companies and affiliated companies, respectively.

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, SEC regulations define these reserves as mining-related and not a part of conventional oil and gas reserves. Net proved oil sands reserves were 167 million barrels as of December 31, 2004. 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-67.

Noteworthy amounts in the categories of proved-reserves changes for 2002 through 2004 in the above table are discussed below:

Revisions In 2002, net revisions reduced liquids volumes worldwide by 49 million barrels for consolidated companies. International areas accounted for a net increase of 67 million barrels. The largest upward net revision internationally was 161 million barrels for a contract extension in Angola. The largest negative net revision was 155 million barrels in Indonesia, mainly for the effect of higher year-end prices on the calculation of reserves associated with cost-oil recovery under a production-sharing contract. In the United States, the total downward net

revision was 116 million barrels across many fields in each of the geographic sections. The 199-million-barrel increase for the TCO affiliate was associated with the project approval to expand gas processing facilities.

In 2003, net revisions increased reserves by 57 million barrels for consolidated companies. Whereas net U.S. reserve changes were minimal, international volumes increased 66 million barrels. The largest increase was in Kazakhstan in the Asia-Pacific area based on an updated geologic model for one field. The 200-million-barrel increase for TCO was based on an updated model of reservoir and well performance.

FS-64

TABLE V – RESERVE QUANTITY INFORMATION – Continued

In 2004, net revisions decreased reserves 218 million barrels for consolidated companies and increased reserves for affiliates by 204 million barrels. For consolidated companies, the decrease was composed of 161 million barrels for international areas and 57 million barrels for the United States. The largest downward revision internationally was 70 million barrels in Africa. One field in Angola accounted for the majority of the net decline as changes were made to oil-in-place estimates based on reservoir performance data. One field in the Asia-Pacific area essentially accounted for the 43-million-barrel downward revision for that region. The revision was associated with reduced well performance. Part of the 36-million-barrel net downward revision for Indonesia was associated with the effect of higher year-end prices on the calculation of reserves for cost-oil recovery under a production-sharing contract. In the United States, the 68-million-barrel net downward revision in the Gulf of Mexico area was across several fields and based mainly on reservoir analyses and

assessments of well performance. For affiliated companies, the 206-million-barrel increase for TCO was based on an updated assessment of reservoir performance for the Tengiz Field. Partially offsetting this net increase was a downward effect of higher year-end prices on the variable royalty-rate calculation. Downward revisions also occurred in other geographic areas because of the effect of higher year-end prices on various production-sharing terms and variable royalty calculations.

Improved Recovery In 2002, improved recovery increased liquids volumes worldwide by 239 million barrels for consolidated companies. The largest increase of 99 million barrels occurred in the United States, primarily in the California region due to pattern modifications, injector conversions and infill drilling on a large heavy oil field under thermal recovery.

Extensions and Discoveries In 2002, extensions and discoveries increased liquids volumes worldwide by 442 million barrels for consolidated companies. The largest increase was 301 million barrels in Africa, principally 172 million barrels reflecting the project sanction of a recent discovery in Nigeria and 96 million barrels associated with approval of several development projects in Angola.

NET PROVED RESERVES OF NATURAL GAS


	Consolidated Companies
	United States												International
				Gulf of						Total						Asia-									Total						Affiliated Companies
Billions of cubic feet	Calif.			Mexico			Other			U.S.			Africa			Pacific			Indonesia			Other			Int'l.			Total			TCO			Hamaca

RESERVES AT JAN. 1, 2002		341			2,361			4,685			7,387			1,872			4,239			520			3,088			9,719			17,106			2,262			42
Changes attributable to:
Revisions		16			(200	)		(414	)		(598	)		277			375			15			92			759			161			293			1
Improved recovery		9			11			1			21			42			–			4			10			56			77			–			–
Extensions and discoveries		5			229			161			395			134			227			33			103			497			892			–			–
Purchases¹		–			65			28			93			–			8			–			–			8			101			–			–
Sales²		–			–			(3	)		(3	)		–			–			–			–			–			(3	)		–			–
Production		(46	)		(414	)		(418	)		(878	)		(27	)		(203	)		(54	)		(369	)		(653	)		(1,531	)		(66	)		–

RESERVES AT DEC. 31, 2002		325			2,052			4,040			6,417			2,298			4,646			518			2,924			10,386			16,803			2,489			43
Changes attributable to:
Revisions		25			(106	)		(525	)		(606	)		342			879			36			976			2,233			1,627			109			70
Improved recovery		15			7			1			23			17			–			15			35			67			90			–			–
Extensions and discoveries		–			270			118			388			3			76			12			47			138			526			–			–
Purchases¹		–			8			–			8			–			7			–			55			62			70			–			–
Sales²		(1	)		(12	)		(51	)		(64	)		–			–			–			(6	)		(6	)		(70	)		–			–
Production		(41	)		(378	)		(394	)		(813	)		(18	)		(235	)		(61	)		(366	)		(680	)		(1,493	)		(72	)		(1	)

RESERVES AT DEC. 31, 2003		323			1,841			3,189			5,353			2,642			5,373			520			3,665			12,200			17,553			2,526			112
Changes attributable to:
Revisions		27			(391	)		(316	)		(680	)		346			236			21			325			928			248			963			23
Improved recovery		2			–			1			3			7			–			13			–			20			23			–			–
Extensions and discoveries		1			54			89			144			16			39			2			13			70			214			–			–
Purchases¹		–			5			–			5			–			4			–			–			4			9			–			–
Sales²		–			(147	)		(289	)		(436	)		–			–			–			(111	)		(111	)		(547	)		–			–
Production		(39	)		(298	)		(348	)		(685	)		(32	)		(247	)		(54	)		(354	)		(687	)		(1,372	)		(76	)		(1	)

RESERVES AT DEC. 31, 2004³		314			1,064			2,326			3,704			2,979			5,405			502			3,538			12,424			16,128			3,413			134

DEVELOPED RESERVES⁴
At Jan. 1, 2002		284			1,976			3,986			6,246			444			2,920			250			2,231			5,845			12,091			1,477			6
At Dec. 31, 2002		266			1,770			3,600			5,636			582			2,934			262			2,157			5,935			11,571			1,474			6
At Dec. 31, 2003		265			1,572			2,964			4,801			954			3,627			223			3,043			7,847			12,648			1,789			52
At Dec. 31, 2004		252			937			2,191			3,380			1,108			3,701			271			2,273			7,353			10,733			2,584			63


¹	Includes reserves acquired through property exchanges.


²	Includes reserves disposed of through property exchanges.


³	Net reserve changes (excluding production) in 2004 consist of (543) billion cubic feet of developed reserves and 490 billion cubic feet of undeveloped reserves for consolidated companies and 883 billion cubic feet of developed reserves and 103 billion cubic feet of undeveloped reserves for affiliated companies.


⁴	During 2004, the percentages of undeveloped reserves at December 31, 2003, transferred to developed reserves were 4 percent and 6 percent for consolidated companies and affiliated companies, respectively.

FS-65


	Supplemental Information on Oil and Gas Producing Activities – Continued

TABLE V – RESERVE QUANTITY INFORMATION – Continued

Sales In 2004, sales of liquids volumes reduced reserves of consolidated companies by 179 million barrels. Sales totaled 130 million barrels in the United States and 33 million barrels in the “other” international region. Sales in the “other” region of the United States totaled 103 millions barrels, with two fields accounting for approximately one-half of the volume. The 27 million barrels sold in the Gulf of Mexico reflect the sale of a number of Shelf properties. The “other” international sales include the disposal of western Canada properties and several fields in the United Kingdom. All the sales were associated with the company’s program to dispose of assets deemed nonstrategic to the portfolio of producing properties.

Noteworthy amounts in the categories of proved-reserves changes for 2002 through 2004 in the table on page FS-65 are discussed below:

Revisions In 2002, reserves were revised upward by a net 161 billion cubic feet (BCF) for consolidated companies, as increases of 759 BCF internationally were partially offset by net downward revisions of 598 BCF in the United States. Internationally, the majority of the 277 BCF net upward revision in Africa was associated primarily with a performance assessment of several fields and a multifield gas development project. An increase of 375 BCF in the Asia-Pacific region included the effect of securing a contract to supply LNG to China markets from company producing operations in Australia. In the United States, about one-fourth of the 598 BCF net downward revision was associated with two fields in the midcontinent region based on an updated assessment of production performance and changes to operating conditions of the wells. Most of the remaining negative revision was associated with reviews of performance in many fields. For the TCO affiliate in Kazakhstan, the 293 BCF increase related mainly to project approval to expand gas processing facilities.

In 2003, revisions accounted for a net increase of 1,627 BCF for consolidated companies, as net increases of 2,233 BCF internationally were partially offset by net downward revisions of 606 BCF in the United States. Internationally, the net 879 BCF increase in the Asia-Pacific region related primarily to Australia and Kazakhstan. In Australia, the increase was associated mainly with a change to the probabilistic method of aggregating the reserves for multiple fields produced through common offshore infrastructure into a single LNG plant. The increase in Kazakhstan related to an updated geologic model for one field and higher gas sales to a third-party processing plant. The net 976 BCF increase in the “Other” international area was mainly the result of operating contract extensions for two fields in South America. In the United States, about one-third of the net 606 BCF negative revision related to two coal bed methane fields in the midcontinent region, based on performance data for producing wells. Downward revisions for the balance of the write-down were associated with several fields, based on assessments of well performance and other data.

In 2004, revisions increased reserves for consolidated companies by a net 248 BCF, composed of increases of 928 BCF internationally and decreases of 680 BCF in the United States. Internationally, about half of the 346 BCF increase in Africa related to properties in Nigeria, for which changes were associated with well performance reviews, development drilling and lease fuel calculations. The 236 BCF addition in the Asia-Pacific

region was related primarily to reservoir analysis for a single field. Most of the 325 BCF in the “Other” international area is related to a new gas sales contract in Trinidad and Tobago. In the United States, the net 391 BCF downward revision in the Gulf of Mexico was related to well-performance reviews and technical analyses in several fields. Most of the net 316 BCF negative revision in the “Other” U.S. area related to two coal bed methane fields in the midcontinent region and their associated wells’ performance. The 963 BCF increase for TCO was connected with updated analyses of reservoir performance and processing plant yields.

Extensions and Discoveries In 2002, consolidated companies increased reserves by 892 BCF, including 395 BCF in the United States and 227 BCF in the Asia-Pacific region. In the United States, 229 BCF was added in the Gulf of Mexico and 161 BCF in the “other” region, primarily due to drilling activities. The addition in Asia-Pacific resulted from a gas supply contract in Australia that enabled booking of a previous discovery.

In 2003, extensions and discoveries accounted for an increase of 526 BCF for consolidated companies, reflecting a 388 BCF increase in the United States, with 270 BCF added in the Gulf of Mexico and 118 BCF in the “other” region. The Gulf of Mexico increase includes discoveries in several offshore Louisiana fields, with a large number of fields in Texas, Louisiana and other states accounting for the increase in “other.”

In 2004, extensions and discoveries accounted for an increase of 214 BCF, reflecting an increase in the United States of 144 BCF, with 89 BCF added in the “other” region and 54 BCF added in the Gulf of Mexico through drilling activities in a large number of fields.

Sales In 2004, sales for consolidated companies totaled 547 BCF. Of this total, 436 BCF was in the United States and 111 BCF in the “other” international region. In the United States, “other” region sales accounted for 289 BCF, reflecting the disposal of a large number of smaller properties, including a coal bed methane field. Gulf of Mexico sales of 147 BCF reflected the sale of Shelf properties, with four fields accounting for more than one-third of the total sales. Sales in the “other” international region reflected the disposition of the properties in Western Canada and the United Kingdom.

FS-66

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 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions, and include estimated costs for asset retirement obligations. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10 percent

midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced.

The information provided does not represent management’s estimate of the company’s expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under FAS 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the company’s future cash flows or value of its oil and gas reserves. In the following table, “Standardized Measure Net Cash Flows” refers to the standardized measure of discounted future net cash flows.


	Consolidated Companies
	United States												International
				Gulf of						Total						Asia-									Total						Affiliated Companies
Millions of dollars	Calif.			Mexico			Other			U.S.			Africa			Pacific			Indonesia			Other			Int’l.			Total			TCO			Hamaca

AT DECEMBER 31, 2004
Future cash inflows from production	$	32,793		$	19,043		$	28,676		$	80,512		$	64,628		$	35,960		$	25,313		$	30,061		$	155,962		$	236,474		$	61,875		$	12,769
Future production costs		(11,245	)		(3,840	)		(7,343	)		(22,428	)		(10,662	)		(8,604	)		(12,830	)		(7,884	)		(39,980	)		(62,408	)		(7,322	)		(3,734	)
Future devel. costs		(1,731	)		(2,389	)		(667	)		(4,787	)		(6,355	)		(2,531	)		(717	)		(1,593	)		(11,196	)		(15,983	)		(5,366	)		(407	)
Future income taxes		(6,706	)		(4,336	)		(6,991	)		(18,033	)		(29,519	)		(9,731	)		(5,354	)		(9,914	)		(54,518	)		(72,551	)		(13,895	)		(2,934	)

Undiscounted future net cash flows		13,111			8,478			13,675			35,264			18,092			15,094			6,412			10,670			50,268			85,532			35,292			5,694
10 percent midyear annual discount for timing of estimated cash flows		(6,656	)		(2,715	)		(6,110	)		(15,481	)		(9,035	)		(6,966	)		(2,465	)		(3,451	)		(21,917	)		(37,398	)		(22,249	)		(3,817	)

STANDARDIZED MEASURE NET CASH FLOWS	$	6,455		$	5,763		$	7,565		$	19,783		$	9,057		$	8,128		$	3,947		$	7,219		$	28,351		$	48,134		$	13,043		$	1,877

AT DECEMBER 31, 2003
Future cash inflows from production	$	30,307		$	23,521		$	33,251		$	87,079		$	55,532		$	33,031		$	26,288		$	29,987		$	144,838		$	231,917		$	56,485		$	9,018
Future production costs		(10,692	)		(5,003	)		(9,354	)		(25,049	)		(8,237	)		(6,389	)		(11,387	)		(6,334	)		(32,347	)		(57,396	)		(6,099	)		(1,878	)
Future devel. costs		(1,668	)		(1,550	)		(990	)		(4,208	)		(4,524	)		(2,432	)		(1,729	)		(1,971	)		(10,656	)		(14,864	)		(6,066	)		(463	)
Future income taxes		(6,073	)		(5,742	)		(7,752	)		(19,567	)		(25,369	)		(9,932	)		(5,993	)		(7,888	)		(49,182	)		(68,749	)		(12,520	)		(2,270	)

Undiscounted future net cash flows		11,874			11,226			15,155			38,255			17,402			14,278			7,179			13,794			52,653			90,908			31,800			4,407
10 percent midyear annual discount for timing of estimated cash flows		(6,050	)		(3,666	)		(7,461	)		(17,177	)		(8,482	)		(6,392	)		(3,013	)		(5,039	)		(22,926	)		(40,103	)		(20,140	)		(2,949	)

STANDARDIZED MEASURE NET CASH FLOWS	$	5,824		$	7,560		$	7,694		$	21,078		$	8,920		$	7,886		$	4,166		$	8,755		$	29,727		$	50,805		$	11,660		$	1,458

AT DECEMBER 31, 2002*
Future cash inflows from production	$	27,111		$	19,671		$	31,130		$	77,912		$	52,513		$	31,099		$	28,451		$	26,531		$	138,594		$	216,506		$	52,457		$	9,777
Future production costs		(11,071	)		(5,167	)		(10,077	)		(26,315	)		(6,435	)		(4,534	)		(9,552	)		(5,970	)		(26,491	)		(52,806	)		(4,959	)		(1,730	)
Future devel. costs		(1,769	)		(748	)		(1,116	)		(3,633	)		(3,454	)		(2,516	)		(1,989	)		(1,868	)		(9,827	)		(13,460	)		(5,377	)		(578	)
Future income taxes		(4,829	)		(4,655	)		(6,747	)		(16,231	)		(25,060	)		(10,087	)		(7,694	)		(6,797	)		(49,638	)		(65,869	)		(11,899	)		(2,540	)

Undiscounted future net cash flows		9,442			9,101			13,190			31,733			17,564			13,962			9,216			11,896			52,638			84,371			30,222			4,929
10 percent midyear annual discount for timing of estimated cash flows		(4,713	)		(2,493	)		(6,666	)		(13,872	)		(8,252	)		(6,297	)		(3,674	)		(3,691	)		(21,914	)		(35,786	)		(18,964	)		(3,581	)

STANDARDIZED MEASURE NET CASH FLOWS	$	4,729		$	6,608		$	6,524		$	17,861		$	9,312		$	7,665		$	5,542		$	8,205		$	30,724		$	48,585		$	11,258		$	1,348

* 2002 includes certain reclassifications to conform to 2004 presentation.

FS-67


	Supplemental Information on Oil and Gas Producing Activities – Continued

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
Millions of dollars	2004			2003			2002			2004			2003			2002

PRESENT VALUE AT JANUARY 1	$	50,805		$	48,585		$	23,748		$	13,118		$	12,606		$	6,396

Sales and transfers of oil and gas produced net of production costs		(18,843	)		(16,630	)		(13,161	)		(1,602	)		(1,054	)		(829	)
Development costs incurred		3,579			3,451			3,695			1,104			750			800
Purchases of reserves		58			97			181			–			–			–
Sales of reserves		(3,734	)		(839	)		(42	)		–			–			–
Extensions, discoveries and improved recovery less related costs		2,678			5,445			7,472			–			–			–
Revisions of previous quantity estimates		1,611			1,200			180			970			653			917
Net changes in prices, development and production costs		6,173			1,857			40,802			266			(1,187	)		6,722
Accretion of discount		8,139			7,903			3,987			1,818			1,709			895
Net change in income tax		(2,332	)		(264	)		(18,277	)		(754	)		(359	)		(2,295	)

Net change for the year		(2,671	)		2,220			24,837			1,802			512			6,210

PRESENT VALUE AT DECEMBER 31	$	48,134		$	50,805		$	48,585		$	14,920		$	13,118		$	12,606

*2003 and 2002 conformed to 2004 presentation.

FS-68

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, filed as Exhibit 3.2 for ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 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 Non-Employee Directors’ Equity Compensation and Deferral Plan, approved by the company’s stockholders on May 22, 2003, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated March 24, 2003, 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 April 1, 2002, filed as Exhibit 10.3 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated herein by reference.

	10	.4	ChevronTexaco Corporation Long-Term Incentive Plan, including January 28, 2004 amendments, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated March 26, 2004 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	.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, filed as Exhibit 10.12 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.

	12	.1*	Computation of Ratio of Earnings to Fixed Charges (page E-3).

E-1


Exhibit No.			Description


	21	.1*	Subsidiaries of ChevronTexaco Corporation (page E-4 to E-5).

	23	.1*	Consent of PricewaterhouseCoopers LLP (page E-6).

	24	.1	Powers of Attorney for directors of ChevronTexaco Corporation, authorizing the
	to 24	.10*	signing of the Annual Report on Form 10-K on their behalf.

	31	.1*	Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Executive Officer (page E-7).

	31	.2*	Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Financial Officer (page E-8).

	32	.1*	Section 1350 Certification of the company’s Chief Executive Officer (page E-9).

	32	.2*	Section 1350 Certification of the company’s Chief Financial Officer (page E-10).

	99	.1*	Submission of Matters to a Vote of Security Holders (page E-11).

	99	.2*	Definitions of Selected Energy and Financial Terms (page E-12).


*	Filed herewith.

Copies of above exhibits not contained herein are available, to any security holder upon written request to the Corporate Governance Department, ChevronTexaco Corporation, 6001 Bollinger Canyon Road, San Ramon, California 94583.

E-2

1.		the nature of the estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change;

2.		the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.