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

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

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter — $71,712,298,891 (As of June 30, 2003)

Number of Shares of Common Stock outstanding as of February 29, 2004 — 1,069,736,866

Notice of the 2004 Annual Meeting and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2004 Annual Meeting of Stockholders (in Part III)

This Annual Report on Form 10-K of ChevronTexaco Corporation contains forward-looking statements relating to ChevronTexaco’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “projects,” “believes,” “seeks,” “estimates” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, ChevronTexaco undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

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

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 operates in the United States and in more than 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 an affiliate, 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, 2003, ChevronTexaco had 61,533 employees (including 10,951 service station employees), down about 4,500 from year-end 2002. Approximately 26,000, or 42 percent, of the company’s employees were employed in U.S. operations, of which approximately 3,400 were unionized.

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

Strong competition exists in all sectors of the petroleum and petrochemical industries 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.

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.

Refer to pages FS-2 through FS-4 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.

ChevronTexaco’s primary objective is to achieve sustained financial returns from its operations that will enable it to outperform its competitors. The company has set as a goal to generate the highest total stockholder return among a designated peer group for the five-year period 2000-2004. BP, ExxonMobil and Royal Dutch Shell — among the world’s largest integrated petroleum companies — comprise the company’s designated competitor peer group for this purpose. The company had the highest total stockholder return in this peer group for the 2000-2003 period.

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


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

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

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

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


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

The Corporate Strategic Plan builds on this framework with strategies focused on appropriately balancing financial returns and growth. As a result of a rigorous evaluation of its entire portfolio of assets, the company is exploring potential asset transactions — sales, acquisitions or trades — to increase the efficiency and profitability of continuing operations and to enhance the economic value of its asset base. The company expects that its worldwide exploration and production business will continue to be its most important business, with development of its large worldwide proved and unproved natural gas reserves as a primary strategy to expand the company’s base of production and to capture economic value from emerging natural gas market opportunities. The company is also seeking to deliver improved and competitive returns from its worldwide downstream businesses. In January 2004, the company’s global downstream organization began operating along global functional lines rather than geographical functional lines in order to lower costs, improve efficiency and achieve sustained improvements in financial performance.

On October 9, 2001, Texaco Inc. (Texaco) became a wholly owned subsidiary of Chevron Corporation (Chevron) pursuant to a merger transaction, and Chevron changed its name to ChevronTexaco Corporation. The combination was accounted for as a pooling of interests, and each share of Texaco common stock was converted on a tax-free basis into the right to receive 0.77 shares of ChevronTexaco common stock. In the merger, ChevronTexaco issued approximately 425 million shares of common stock, representing about 40 percent of the outstanding ChevronTexaco common stock after the merger. Further discussion of the Texaco merger transaction is contained on page FS-5 and in Note 2 on page FS-30 of this Annual Report on Form 10-K.

The company’s largest business segments are exploration and production (upstream) and refining, marketing and transportation (downstream). Chemicals is also a significant segment, conducted mainly by the company’s 50 percent-owned affiliate — Chevron Phillips Chemical Company LLC (CPChem). The petroleum activities of the company are widely dispersed geographically. The company has petroleum operations in North America, South America, Europe, Africa, Middle East, Central and Far East Asia, and Australia.

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

ChevronTexaco owns an approximate 26 percent equity interest in the common stock of Dynegy Inc. (Dynegy), an energy merchant engaged in power generation, natural gas liquids processing and marketing, and regulated energy delivery. The company also holds investments in Dynegy notes and preferred stock. During 2003, the company exchanged its $1.5 billion aggregate principal amount of Dynegy Series B preferred Stock, which was due for redemption at par value in November 2003, for cash and new Dynegy securities. Refer to pages FS-10 and FS-11 for further information relating to the company’s investment in Dynegy.

Tabulations of segment sales and other operating revenues, earnings, income taxes and assets, by United States and International geographic areas, for the years 2001 to 2003 may be found in Note 9 to the consolidated financial statements beginning on page FS-34 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-38 to FS-40.

The company’s worldwide operations can be affected significantly by changing economic, tax, regulatory and political environments in the various countries in which it operates, including the United States. Environmental regulations and government policies concerning economic development, energy and taxation may have a significant effect on the company’s operations. Management evaluates the economic and political risk of initiating, maintaining or expanding operations in any geographical area. The company monitors political events worldwide and the possible threat these may pose to its activities — particularly the company’s oil and gas exploration and production operations — and the safety of the company’s employees. Political and community unrest has disrupted the company’s production in the past, most recently in Nigeria and Venezuela.

A discussion of the company’s capital and exploratory expenditures is contained on pages FS-11 and FS-12 of this Annual Report on Form 10-K.

The following table summarizes the company’s and affiliates’ net production of crude oil and natural gas liquids, natural gas, and oil-equivalent production for 2003 and 2002.


	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	Located between the Kingdom of Saudi Arabia and the State of Kuwait.

	⁴	The company sold its interest in Papua New Guinea and resigned operatorship of the Kutubu, Gobe and Moran oil fields in the fourth quarter of 2003.

	⁵	Affiliates include Tengizchevroil (TCO) in Kazakhstan and Hamaca in Venezuela.

	⁶	Includes natural gas consumed on lease of 327 and 320 million cubic feet per day in 2003 and 2002, respectively.

	⁷	Does not include total field production under the Boscan operating service agreement in Venezuela of 99 and 97 thousand barrels per day for 2003 and 2002, respectively, and synthetic crude oil production from the Athabasca Oil Sands Project in Canada of 15 thousand barrels per day in 2003.

In 2003, ChevronTexaco conducted its exploration and production operations in the United States and approximately 25 other countries. Worldwide net crude oil and natural gas liquids production, including that of affiliates but excluding volumes produced under operating service agreements, decreased by about 5 percent from the 2002 levels. Net worldwide production of natural gas, including affiliates, decreased about 2 percent in 2003.

Net liquids and natural gas production in the United States were both down about 7 percent compared with 2002. The decline in U.S. production in 2003 was primarily attributable to declines in mature fields. In addition to normal field declines in 2003, oil-equivalent production decreased from the absence of 10,000 to 15,000 barrels per day of production the company deemed uneconomic to restore following storm damages in the Gulf of Mexico in late 2002.

International net liquids production, including affiliates, decreased about 4 percent, whereas net natural gas production increased about 5 percent from 2002. In Indonesia, about 29,000 barrels per day of the year-to-year decline was related to the effect of lower cost-oil recovery volumes under production-sharing terms during 2003 and the expiration of a production sharing arrangement in the third quarter of 2002.

For the past five years, the company’s worldwide oil-equivalent production has followed a downward trend with 2003 production at 89 percent of 1999 levels, equivalent to an average annual decline rate of slightly more than 2 percent. During this time period, increases in international oil-equivalent production were more than offset by decreases in the United States.

For 2004, the company currently anticipates lower oil-equivalent production rates in the United States as a result of normal field declines, the effect of property sales and opportunity limitations. The ultimate level of worldwide production in 2004 remains uncertain due to the potential for constraints imposed by the Organization of Petroleum Exporting Countries (OPEC), and disruptions caused by weather, local civil unrest and other economic factors.

At December 31, 2003, 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.


	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 2004, 2005 and 2006 if production is not established are 8,238, 17,436 and 5,416, respectively.

Refer to Table IV on page FS-56 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 2003, 2002 and 2001. The following table summarizes gross and net productive wells at year-end 2003 for the company and its affiliates.


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

Table V on page FS-57 of this Annual Report on Form 10-K sets forth the company’s net proved oil and gas reserves, by geographic area, as of December 31, 2003, 2002 and 2001. During 2004, the company will file estimates of oil and gas reserves with the Department of Energy, Energy Information Agency, consistent with the reserve data reported on page FS-57 of this Annual Report on Form 10-K.

In 2003, ChevronTexaco’s worldwide oil and oil-equivalent gas barrels of net proved reserves additions exceeded production, with a replacement rate of 108 percent of net production, including sales and acquisitions. Excluding sales and acquisitions, the replacement rate was 114 percent of net production. Reserve additions included extensions of the Guajira Contract in Colombia and the Danish Underground Consortium Contract in Denmark; initial booking of the Tahiti Field in the Gulf of Mexico; reservoir studies and analyses at the Tengiz and Karachaganak fields in Kazakhstan; and improved recovery activity primarily in Indonesia and the United States. The following table summarizes the company’s net additions to net proved reserves of crude oil and natural gas liquids and natural gas compared with net production during 2003.


	¹	MMBBLS = millions of barrels
	²	BCF = billions of cubic feet
	³	Oil-Equivalent Gas (OEG) conversion ratio is 6,000 cubic feet of gas = 1 barrel of oil
	⁴	Includes equity in affiliates

The company sells crude oil and natural gas from its producing operations under a variety of contractual arrangements. Most contracts generally commit the company to sell quantities based on production from specified properties, but certain gas sales contracts specify delivery of fixed and determinable quantities. During 2002, Dynegy purchased substantially all natural gas and natural gas liquids produced by the company in the United States, excluding Alaska, and supplied natural gas and natural gas liquids feedstocks to the company’s U.S. refineries and chemical plants. The company reached an agreement with Dynegy to terminate the natural gas purchase and sale contracts and other related contracts at the end of January 2003. See pages FS-10 and FS-11 for further information on Dynegy.

In the United States, the company is contractually committed to deliver to third parties and affiliates approximately 160 billion cubic feet of natural gas through 2006 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 600 billion cubic feet of natural gas through 2006 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, Canadian, Colombian and Philippine reserves.

Details of the company’s development expenditures and costs of proved property acquisitions for 2003, 2002 and 2001 are presented in Table I on page FS-53 of this Annual Report on Form 10-K.

The table below summarizes the company’s net interest in productive and dry development wells completed in each of the past three years and the status of the company’s development wells drilling at December 31, 2003. A “development well” is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. “Wells drilling” includes wells temporarily suspended.


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

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

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, 2003. “Exploratory wells” are wells drilled to find and produce oil or gas in unproved areas and include delineation wells, which are wells drilled to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir beyond the proved area. “Wells drilling” 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-28 and FS-29 for further discussion. Increases in the United States, Nigeria and Australia were partially offset by decreases in China and Angola. The wells are suspended pending a final determination of the commercial potential of the related oil and gas deposits. The ultimate disposition of these well costs is dependent on: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory drilling that is under way or firmly planned, and (3) in some cases, securing final regulatory approvals for development.


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

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

Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2003, 2002 and 2001 are presented in Table I on page FS-53 of this Annual Report on Form 10-K.

ChevronTexaco’s 2003 key upstream activities not discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations beginning on page FS-2 of this Annual Report on Form 10-K are presented below. The comments include reference to “net production,” which excludes partner shares and royalty interests. “Total production” includes these components. In addition to the activities discussed, ChevronTexaco was active in other geographic areas, but these activities were less significant.

The United States exploration and production activities are concentrated in the Gulf of Mexico, California, Louisiana, Texas, New Mexico and the Rocky Mountains. As part of the ongoing effort to improve competitive performance and increase operating efficiency, the company announced plans in 2003 to sell interests in non-strategic producing properties in the United States. The majority of these properties are located in 15 states and the Outer Continental Shelf of the Gulf of Mexico. The company expects to retain about 400 core fields and anticipates the divestment program will be substantially completed in 2004.

Gulf of Mexico: Combining the shelf and deepwater interests in the Gulf of Mexico, average daily net production during 2003 were 169,000 barrels of crude oil, 1 billion cubic feet of natural gas and 19,700 barrels of natural gas liquids.

In deepwater, the company has an interest in three significant developments: Petronius, Genesis and Typhoon. Petronius, 50 percent-owned and operated, maintained a daily production of approximately 30,000 barrels of net oil-equivalent in 2003. The 57 percent-owned and operated Genesis averaged production of approximately 20,000 barrels of net oil-equivalent per day in 2003. Typhoon, which is 50 percent-owned and operated, had average production of approximately 14,000 barrels of net oil-equivalent per day in 2003, including production from the Boris field that utilizes the Typhoon production facility.

In exploration, there were four new deepwater discoveries in 2003 — Sturgis and Perseus, in which the company has a 50 percent interest in each, and Tubular Bells and Saint Malo, which the company’s interest is 30 percent and 12.5 percent, respectively. The company drilled a well in the Tonga prospect in 2003. The data from this well is under evaluation. Additionally, under terms of an agreement with BP, ChevronTexaco earned the right to operate the Blind Faith discovery and increased its ownership to 50 percent. Appraisal work was completed in the Tahiti discovery.

Mid-Continent: Onshore operations in the mid-continent United States are concentrated in Texas, Oklahoma, Kansas, Alabama and the Rocky Mountain states. Net production of natural gas averaged 822 million cubic feet per day through development drilling activity, combined with a focus on maintaining base production with workovers, artificial lift and facility optimization. Net production of crude oil and natural gas liquids averaged 32,000 barrels per day during the year. Capital spending was focused on natural gas development with major programs in the Rockies, East Texas and South Texas.

Permian: Permian operations are located predominantly in southeastern New Mexico and West Texas. During 2003, daily net production averaged 110,500 barrels of crude oil and natural gas liquids and 257 million cubic feet of natural gas.

San Joaquin Valley: ChevronTexaco is the largest producer in California. In 2003, average daily net production was 225,500 barrels of crude oil, 112 million cubic feet of natural gas and 4,800 barrels of natural gas liquids. Approximately 85 percent of the crude oil production is considered heavy oil (typically

Global Natural Gas Projects: In November 2003, ChevronTexaco received approval for a Deepwater Port License by U.S. government authorities to construct, own and operate a liquefied natural gas (LNG) receiving and regasification terminal, Port Pelican, to be located offshore Louisiana to serve the North American market. Efforts are under way in 2004 to obtain project approval. The company also filed permits to construct an LNG receiving and regasification terminal to be located approximately eight miles off the coast of Baja California, Mexico. ChevronTexaco is working with Mexican authorities to secure permit approvals for the project.

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.

In 2003, daily net production from the 33 CNL-operated fields averaged 113,100 barrels of crude oil, 2,400 barrels of liquefied petroleum gas (LPG) and 50 million cubic feet of natural gas. Net production from five TOPCON operating fields during the year averaged approximately 7,200 barrels of crude oil per day. 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 remained shut-in at year-end while the company continued to evaluate options for safe and secure restoration of production.

The onshore and offshore engineering, procurement and construction bids were received in 2003 for Phase 3 of the Escravos Gas Project, which includes adding a second gas plant and expanding processing capacity to 680 million cubic feet per day and is targeted for completion in 2007. ChevronTexaco holds a 40 percent working interest in the Escravos Gas Project, which has the capacity to process 285 million cubic feet of natural gas per day.

Front-end engineering and design and site preparations have been completed for the planned gas-to-liquids (GTL) facility at Escravos. This proposed 33,000-barrel-per-day GTL project is the company’s first project to use the Sasol Chevron Global Joint Venture’s technology and operational expertise. Project start-up is expected to be in 2007. ChevronTexaco will ultimately hold about a 38 percent beneficial interest.

The company also continued activities in the deepwater Agbami development. In 2003, a pre-unitization agreement was completed between ChevronTexaco and the Blocks 216 and 217 participants. Initial production is expected in 2007.

Successful results were achieved in 2003 from the Aparo-3 appraisal well and the Nsiko-1 wildcat well in the deepwater Block OPL-249, in which the company is entitled to a variable equity interest over the life of the field.

OPL-222 activities continued in 2003 with the successful completion of appraisal programs involving Usan-3, Usan-4 and Ukot-2, in which ChevronTexaco holds a 30 percent interest. Exploration activities on the shelf included the completion of the Okagba-2 appraisal well along with the successful Sonam-4 appraisal well.

The company and its partners in the Brass River Consortium agreed to advance plans for the front-end engineering and design work for a new LNG facility at Brass River in Nigeria.

Angola: ChevronTexaco is the largest producer of crude oil and natural gas in Angola and the first to produce in the deepwater. Cabinda Gulf Oil Company Limited (CABGOC), a wholly owned subsidiary of ChevronTexaco, is operator of two concessions, Blocks 0 and 14, off the 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 three areas — A, B and C — composed of 21 fields producing 128,000 barrels per day of net liquids in 2003. Area A, comprising 16 fields that are currently producing, averaged daily net production of approximately 82,000 barrels of crude oil and 1,000 barrels of LPG in 2003. Area B, which has three fields producing, averaged net production of 37,000 barrels of crude oil per day. Area C averaged net production of 8,000 barrels of crude oil per day from two producing fields.

In Block 14, net production in 2003 from the Kuito Field, Angola’s first deepwater producing area, averaged approximately 19,000 barrels of crude oil per day. The Benguela Belize-Lobito Tomboco development includes a phased development of the Benguela, Belize, Lobito and Tomboco fields, with Phase 1 currently estimated to start up by the end of 2005. Phase 2 involves the installation of subsea systems, pipelines and wells for the Lobito and Tomboco fields. The company is the operator and holds a 31 percent interest in Block 14. The Negage prospect is currently under evaluation for commerciality, and feasibility studies continue for the Gabela heavy oil field.

ChevronTexaco has two other concessions in Angola. Block 2, in which the company operates and has a 20 percent interest, and Block FST, in which the company has a 16 percent nonoperated interest, had a combined net production of 7,100 barrels of crude oil per day in 2003.

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.

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 in offshore Congo and adjacent to the company’s concessions in Cabinda. Net production from ChevronTexaco’s concessions in the Republic of Congo averaged 13,300 barrels of crude oil per day in 2003. An assessment of the Moho and Bilondo discoveries progressed during 2003, and a development decision is expected in 2004.

Chad-Cameroon: ChevronTexaco is partner in a project to develop landlocked oil fields in southern Chad and transport crude oil by pipeline to the coast of Cameroon for export to world markets. At the end of 2003, the overall development project was substantially complete. The company’s first sales of Chad production occurred in late 2003. ChevronTexaco has a 25 percent interest in the upstream operations and has approximately a 23 percent interest in the pipeline.

Equatorial Guinea: ChevronTexaco is a 45 percent partner and operator of Block L offshore the Republic of Equatorial Guinea. The first exploration well, Ballena-1, was completed in April 2003, and the partnership is currently progressing with the evaluation of the block.

China: ChevronTexaco has a 33 percent interest in Block 16/08, located in the Pearl River Delta Mouth Basin. Daily net production from the six fields in this block averaged 14,700 barrels of crude oil per day in 2003. The company has a 25 percent interest in QHD-32-6 in Bohai Bay, which had 2003 average net production of 8,300 barrels of crude oil per day.

Indonesia: ChevronTexaco’s interests in Indonesia are managed by two wholly owned subsidiaries, P.T. Caltex Pacific Indonesia (CPI) and Amoseas Indonesia (AI). CPI accounts for about 40 percent of Indonesia’s total crude oil output and holds an interest in five production-sharing contracts (PSCs). AI is a power generation company that operates the Darajat geothermal contract area in West Java and a

ChevronTexaco’s share of net production during 2003 was 251,000 barrels of oil-equivalent per day. CPI continues to execute projects that are designed to optimize production from its existing reservoirs. The Duri Field in the Rokan Block, under steamflood since 1985, is the largest steamflood project in the world, with net production averaging 116,000 barrels of crude oil per day in 2003. ChevronTexaco’s net production from South Natuna Sea Block B in 2003 was about 15,400 barrels of oil-equivalent per day.

Thailand: ChevronTexaco operates Block B8/32 in the Gulf of Thailand with a 52 percent interest. During 2003, the company was awarded the exploration and production rights to two additional offshore concessions. The company’s interests in the newly acquired Blocks G4/43 and 9A are 85 percent and 52 percent, respectively. The company also holds a 33 percent interest 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 three fields: Tantawan, Maliwan and Benchamas. Daily net production in 2003 from these fields was 104 million cubic feet of natural gas and 24,600 barrels of crude oil. During the year, the company drilled 44 development wells and installed three platforms in Block B8/32. In early 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 of crude oil per day). During 2004, an exploration program is planned to continue to evaluate the remaining areas of Block B8/32 and the recently acquired concessions.

Cambodia: ChevronTexaco operates and holds a 70 percent interest in Block A, located offshore Cambodia in the Gulf of Thailand. Efforts are under way to reduce the company’s working interest in the block to 55 percent. The concession covers approximately 1 million net acres. In 2003, ChevronTexaco drilled one exploration well without commercial success. New 3D seismic data has been acquired and processed over a portion of the block, and the drilling of additional exploration wells is planned for 2004.

Australia: ChevronTexaco has a one-sixth interest in the North West Shelf (NWS) Project in offshore Western Australia. Daily net production from the project during 2003 averaged 18,100 barrels of condensate, 282 million cubic feet of natural gas, 17,900 barrels of crude oil and 3,700 barrels of liquefied petroleum gas. Approximately 60 percent of the natural gas was sold, primarily under long-term contracts, in the form of liquefied natural gas (LNG) to major utilities in Japan and South Korea. The remaining natural gas was sold to the Western Australia domestic market. The Train 4 LNG expansion project, which is planned to increase LNG capacity by about 50 percent, is under construction and is expected to have first gas sales by September 2004. The NWS Venture was selected by the People’s Republic of China to be the supplier of LNG for the proposed Guangdong LNG Terminal Project. A 25-year LNG Sale and Purchase Agreement (SPA) for approximately 3.9 trillion cubic feet of natural gas is being negotiated, with first LNG cargoes expected in late 2006 or 2007. In parallel with the execution of the SPA, China National Offshore Oil Corporation (CNOOC) will have the opportunity to acquire participating interest in NWS reserves and production that will supply gas to Guangdong.

The company is operator of and has a 57 percent interest in the undeveloped Gorgon area gas fields offshore northwest Australia. ChevronTexaco is actively pursuing long-term gas sales from Gorgon to Australian industrial customers and in international LNG markets, including China, Japan, South Korea and the west coast of North America. In 2003, the Western Australian government granted in-principle approval, through an act of parliament, for the development and construction of a multibillion-dollar gas processing facility on Barrow Island. This represented one of several milestones toward enabling production of natural gas resources in this area. Additionally, ChevronTexaco signed a Memorandum of Understanding with the Gorgon joint venture partners for the supply of LNG to the North America west coast, over a 20-year period (approximately 1.9 trillion cubic feet in total) beginning in 2008. In October 2003, the Gorgon joint venture partners announced an agreement with CNOOC to negotiate the sale of Gorgon LNG to the People’s Republic of China. The agreement, which is subject to the completion of formal contracts, enables CNOOC to purchase an equity stake in the Gorgon gas development project and to facilitate the sale of LNG into the Chinese market.

In 2003, ChevronTexaco participated in the drilling of the Jansz-3 appraisal well in the Io-Jansz gas field discovery, offshore Western Australia, in which the company holds a 50 percent interest.

Philippines: The company holds a 45 percent interest in the Malampaya natural gas field located about 50 miles offshore Palawan Island. The Malampaya gas-to-power project represents the first offshore production of natural gas in the Philippines. Daily net production was 140 million cubic feet of natural gas and 7,600 barrels of condensate.

Middle East: Saudi Arabia Texaco Inc., a ChevronTexaco affiliate, holds a 60-year concession, originally signed in 1949, to produce onshore crude oil from the Partitioned Neutral Zone (PNZ), located between the Kingdom of Saudi Arabia and the State of Kuwait. The Kingdom of Saudi Arabia and the State of Kuwait each own an undivided 50 percent 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, on which it pays a royalty and other taxes on hydrocarbons produced. During 2003, average net production was 133,700 barrels of crude oil per day and 15 million net cubic feet of natural gas per day. The company also has an exploration agreement in Bahrain. The exploration concessions in Qatar expired in mid-2003.

Kazakhstan: ChevronTexaco holds a 20 percent interest in the Karachaganak project. Phase 2 of the field development, which included construction of gas injection and liquids processing facilities, as well as a 400-mile pipeline that provides access to world markets, was substantially completed at year-end 2003. When fully operational in mid-2004, daily net production is expected to increase to approximately 40,000 barrels of liquids, including 27,900 barrels of processed liquids that will be exported via the company’s 15 percent-owned Caspian Pipeline. Daily net natural gas production is expected to increase to approximately 140 million cubic feet of natural gas. During 2003, Karachaganak net production averaged 21,400 barrels of liquids and 101 million cubic feet of natural gas per day. Also in 2003, ChevronTexaco sold its interest in the North Buzachi oil and gas field.

Papua New Guinea: In 2003, ChevronTexaco sold its interests in Papua New Guinea and resigned operatorship of the Kutubu, Gobe and Moran oil fields.

Europe: ChevronTexaco holds producing interests in 26 fields in Denmark, Norway and the United Kingdom with a combined daily net production of 167,900 barrels of crude oil and 477 million cubic feet of gas. In the United Kingdom, the daily net production was 115,600 barrels of crude oil and 378 million cubic feet of natural gas in 2003. This includes daily net production of 46,600 barrels of crude oil at the Captain Field, ChevronTexaco is the operator with an 85 percent interest. At Britannia, where ChevronTexaco holds a 32 percent interest and shares operatorship, daily net production averaged 10,300 barrels of crude oil and 204 million cubic feet of natural gas. At the Alba Field in the North Sea, where ChevronTexaco holds a 21 percent interest and operatorship, daily net production averaged 17,500 barrels of crude oil and 4 million cubic feet of natural gas. The Erskine Field, the first high-pressure/ high-temperature gas condensate field developed in the North Sea, reported net crude oil production of 9,400 barrels per day, and net natural gas production averaged 52 million cubic feet per day. ChevronTexaco is the operator and holds a 50 percent interest. In early 2004, the company reached agreements to sell its interests in the Galley, Orwell and Statfjord fields. Daily net production from the three fields in 2003 was 14,000 barrels of crude oil and 37 million cubic feet of natural gas.

At the Draugen Field in Norway, ChevronTexaco’s 8 percent share of production during 2003 was 10,300 barrels of crude oil per day. The daily net production from the Danish Underground Consortium was 42,000 barrels of crude oil and 99 million cubic feet of gas. An agreement was announced in October 2003 extending the concession term from 2012 to 2042 and revising other terms of the concession. The agreement was subsequently ratified by the Danish parliament in December 2003.

Canada: As part of ChevronTexaco’s portfolio optimization process, the company intends in 2004 to evaluate opportunities to divest selected mature producing fields — currently producing about 35,000 net

In December 2003, ChevronTexaco was the successful bidder on a 50 percent working interest in eight new exploration licenses totaling 5.2 million acres in the Orphan Basin offshore Newfoundland.

Excluding Athabasca, which is discussed separately on page 21 of this Annual Report on Form 10-K, daily net production in 2003 from the company’s Canadian operations was 73,100 barrels of crude oil and 110 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. Despite a general strike affecting the entire country in early 2003, total Boscan production averaged 98,900 barrels of crude oil per day for the year. In February 2003, ChevronTexaco was awarded the license for offshore Block 2 in the northeastern Plataforma Deltana, including Loran Field, an undeveloped natural gas discovery. The company plans to begin an exploration and delineation program in Block 2 in 2004. Currently the company holds a 60 percent interest.

Argentina: ChevronTexaco operates in Argentina through its subsidiary Chevron San Jorge S.R.L. Chevron San Jorge holds more than 3.8 million exploration and production acres in the Neuquén and Austral basins with working interests ranging from approximately 19 percent to 100 percent in operated license areas. Farm-out agreements are under negotiation in three blocks. Net production in 2003 averaged 64,800 barrels of oil-equivalent per day.

Brazil: ChevronTexaco holds working interests ranging from 20 to 68 percent in six deepwater blocks totaling 1.6 million acres at year-end 2003. Exploration is concentrated in the Campos and Santos basins. During 2003, one block was fully relinquished, and two blocks entered into an assessment phase to further evaluate the commercial potential. In the Frade Field, where the company has a 42.5 percent interest, front-end engineering and design work commenced in the fourth quarter of 2003.

Colombia: ChevronTexaco currently operates 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 with the Colombian national oil company, Ecopetrol, expires in December 2004. A contract extension was signed in December 2003 whereby in 2005 ChevronTexaco will continue to operate the fields and receive 43 percent of the production for the economic life of the fields, as well as continue to operate the BOMT contract until it expires in 2016. Total natural gas production averaged 470 million cubic feet per day in 2003.

Kazakhstan: The company’s 50 percent owned affiliate, Tengizchevroil (TCO), reached agreement with the Republic of Kazakhstan in September 2003 to expand operations at the Tengiz and Korolev fields. The agreement formalizes earlier understandings relating to the Sour Gas Injection/ Second Generation project. The project is expected to increase TCO’s crude oil production capacity from about 285,000 barrels per day to between 430,000 and 500,000 barrels per day in the second half of 2006. TCO 2003 total crude oil production of 280,000 barrels per day was marginally below 2002 production levels, which was attributable to TCO’s largest-ever planned maintenance turnaround during the year.

Venezuela: ChevronTexaco has a 30 percent interest in the Hamaca integrated oil production and upgrading project located in Venezuela’s Orinoco Belt. Development drilling and major facility construction at Hamaca continued through 2003. Upon completion in third quarter 2004, the facility is expected to have upgrade capacity to 190,000 barrels per day of heavy crude oil, creating a lighter, higher-value crude oil.

The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. Prior to February 2003, ChevronTexaco’s equity affiliate, Dynegy, purchased substantially all natural gas and natural gas liquids produced by the company in the United States, excluding Alaska, and supplied natural gas and natural gas liquids feedstocks to the company’s U.S. refineries and chemical plants. At the end of January 2003, the company’s natural gas purchase and sale contracts with Dynegy were terminated. This was preceded by an agreement between ChevronTexaco and Dynegy to discontinue certain commercial arrangements as a result of Dynegy’s decision to exit the gas marketing and trading business. As a result, the company now markets its domestic natural gas production to a variety of third parties through its new unit, ChevronTexaco Natural Gas. The company’s long-term natural gas processing and liquids arrangements with Dynegy were not affected by the early termination of natural gas purchase and sale contracts. During 2003, nearly all of ChevronTexaco’s U.S. natural gas liquids production was sold to Dynegy. Refer to pages FS-10 and FS-11 on Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for further comments on Dynegy.

Outside the United States, the majority of the company’s natural gas sales occur in the United Kingdom, Australia, Canada, Latin America, and in the company’s affiliate operations in Kazakhstan. International natural gas liquids sales primarily 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 of this Annual Report on Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for further information on the company’s natural gas and natural gas liquids sales volumes.

Distillation operating capacity utilization in 2003, adjusted for sales and closures, averaged 91 percent in the United States (including asphalt plants) and 88 percent worldwide (including affiliates), compared with 94 percent in the United States and 89 percent worldwide in the prior year. ChevronTexaco’s capacity utilization at its U.S. fuels refineries averaged 95 percent in 2003, compared with 98 percent in 2002. ChevronTexaco’s capacity utilization of its wholly owned U.S. cracking and coking facilities, which are the primary facilities used to convert heavier products to gasoline and other light products, averaged 86 percent and 85 percent in 2003 and 2002, respectively. The company processed imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 75 percent of ChevronTexaco’s U.S. refinery inputs in 2003.

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

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


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

	⁴	ChevronTexaco ceased refining operations at the Batangas Refinery in November 2003 in advance of the refinery’s conversion into a finished-product terminal.

	⁵	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.

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

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


	¹	Excludes Equilon and Motiva; and 2002 conformed to 2003 presentation.

	²	Principally naphtha, lubricants, asphalt and coke.

In the United States, the company supplies, directly or through dealers and jobbers, more than 7,800 Chevron-branded motor vehicle retail outlets, of which about 1,000 are company-owned or -leased stations. The company’s gasoline market area is concentrated in the southern, southwestern and western states. According to the Lundberg Share of Market Report, ChevronTexaco ranks among the top three gasoline marketers in 14 states.

In Canada — primarily British Columbia — the company’s Chevron-branded products are sold in 165 company-owned or-leased stations.

Outside of the United States and Canada, ChevronTexaco supplies, directly or through dealers and jobbers, approximately 11,600 branded service stations in more than 80 countries. In the Asia-Pacific region, southern and East Africa, and the Middle East, ChevronTexaco uses the Caltex brand name.

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

ChevronTexaco operates across the Caribbean, Central America, and South America with a significant presence in Brazil, using the Texaco brand name.

In addition to the above activities, the company manages other marketing businesses globally. In global aviation fuel marketing, the company markets 440,000 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 residual fuel oils and marine lubricants in more than 65 countries and motor lubricants in more than 180 countries.

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:


	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. Currently, CPC has seven transportation agreements in place which provide the capacity to transport approximately 600,000 barrels of crude oil per day. ChevronTexaco has a 15 percent ownership interest in CPC.

Tankers: ChevronTexaco’s controlled seagoing fleet at December 31, 2003, is summarized in the following table. All controlled tankers were utilized in 2003. 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.

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 2003, the company’s U.S. flag fleet was engaged primarily in transporting refined products between the Gulf Coast

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.

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. During 2003, ChevronTexaco operated a total of 20 double-hull tankers, which includes three additional double-hull tankers that the company took delivery of in 2003. The company is a member of many oil-spill-response cooperatives in areas around the world in which it operates.

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.

A new olefins and polyolefins complex was commissioned in Qatar in 2003. The complex is owned and operated by Qatar Chemical Company Ltd., a joint venture between CPChem, with a 49 percent interest, and Qatar General Petroleum, which owns the remaining 51 percent.

Also during 2003, a 50-50 joint venture with BP Solvay commenced operations of a new high-density polyethylene (HDPE) facility at a CPChem site in the Houston, Texas area. The jointly owned 700-million-pounds per-year HDPE facility is among the largest of its kind in the world and uses CPChem proprietary manufacturing technology.

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, Japan and Brazil and has equity interests in facilities in India and Mexico.

The company’s coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), owned and operated two surface mines and one underground mine at year-end 2003. In addition, final reclamation activities were under way at two mines that are scheduled to close. 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 in Venezuela and Colombia.

Sales of coal from P&M’s wholly owned mines and from its affiliates were 13.4 million tons, a decrease of 10 percent from 2002. The reduction resulted from the absence of sales in 2003 from the company’s mining operations in northeastern New Mexico, where production ceased in late 2002. Lower production from P&M’s surface mine, located near Gallup, New Mexico, also contributed to the decline.

At year-end 2003, P&M controlled approximately 189 million tons of developed and undeveloped coal reserves, including significant reserves of environmentally desirable low-sulfur fuel. The company is contractually committed to deliver approximately 13 million tons of coal per year through the end of 2006 and believes it can satisfy these contracts from existing coal reserves.

In Canada, ChevronTexaco holds a 20 percent 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 April 2003 when the Scotford Upgrader

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, Asia and Europe, GPG manages the production of more than 3,500 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.

ChevronTexaco Worldwide Gasification Technology (WGT) is used to convert a wide variety of hydrocarbon feedstocks into clean synthesis gas. The synthesis gas can be used as a feedstock for basic chemicals or to generate electricity in low-emission power plants. ChevronTexaco has licensed its gasification technology to more than 60 plants worldwide.

The 50-50 Sasol Chevron Global Joint Venture was established in October 2000 to develop a worldwide gas-to-liquids (GTL) business. Projects to build GTL plants are being considered for Qatar, Nigeria and Australia.

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

Additionally, ChevronTexaco’s Technology Ventures Company focuses on the identification, growth and commercialization of emerging technologies that have the potential to change or 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 advanced batteries for distributed power and transportation systems and hydrogen fuel storage.

During 2003, the company completed the worldwide implementation of a new information technology infrastructure encompassing computing, data management, security, and connectivity of partners, suppliers and employees. The architecture, known as “Net Ready,” provides the foundation for the company to cost-effectively and rapidly integrate advances in computing and network-based technology.

ChevronTexaco’s research and development expenses were $238 million, $221 million and $209 million for the years 2003, 2002 and 2001, 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.

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

In 2003, the company’s U.S. capitalized environmental expenditures were $178 million, representing approximately 8 percent of the company’s total consolidated U.S. capital and exploratory expenditures. These environmental expenditures include capital outlays to retrofit existing facilities, as well as those associated with new facilities. The expenditures are predominantly in the petroleum segment and relate mostly to air-and-water quality projects and activities at the company’s refineries, oil and gas producing facilities, and marketing facilities. For 2004, the company estimates U.S. capital expenditures for environmental control facilities will be $260 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 2003 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-16 to FS-18 of this Annual Report on Form 10-K.

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

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

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

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-53 to FS-59 of this Annual Report on Form 10-K. Note 15, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-40 of this Annual Report on Form 10-K.

Chevron Products Company, a division of Chevron U.S.A. Inc., paid $228,275 to the Bay Area Air Quality Management District (BAAQMD) and $50,000 to the District Attorney of the County of Contra Costa, California, in settlement of 35 alleged violations of the BAAQMD’s air regulations at the company’s Richmond Refinery.

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.

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-51 of this Annual Report on Form 10-K.

The selected financial data for years 1999 through 2003 are presented on page FS-52 of this Annual Report on Form 10-K.

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.

The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Financial and Derivative Instruments,” beginning on page FS-15 and Note 8 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-33.

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.

The company maintains “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”), that are designed to ensure that information required to be disclosed in reports the company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including the company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating its disclosure controls and procedures, management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. The company’s disclosure controls and procedures have been designed to meet, and management believes that they meet, reasonable assurance standards. Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K, the Chief Executive Officer and Chief Financial Officer have concluded that, subject to the limitations noted above, the company’s disclosure controls and procedures were effective to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to them by others within those entities.


	As of the last quarter, 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.

The information on Directors appearing under the heading “Election of Directors — Nominees For Directors” in the Notice of the 2004 Annual Meeting of Stockholders and 2004 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 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 25 and 26 of this Annual Report on Form 10-K for information about Executive Officers of the company.

The 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), Franklyn G. Jenifer, Charles R. Shoemate, Thomas A. Vanderslice, and John A. Young, all of whom are independent under the New York Stock Exchange Corporate Governance Rules. Of these Audit Committee members, Sam Ginn, Charles R. Shoemate, Thomas A. Vanderslice, and John A. Young 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 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. ChevronTexaco believes all filing requirements were complied with during 2003.

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”). The Code is available on the company’s Internet Web site at http://www.chevrontexaco.com/.

The information appearing under the headings “Executive Compensation” and “Directors Compensation” in the Notice of the 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated herein by reference in this Annual Report on Form 10-K.

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 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 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 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.

The information appearing under the heading “Board Operations — Certain Business Relationships Between ChevronTexaco and its Directors and Officers” in the Notice of the 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.

The information appearing under the headings “Ratification of Independent Auditors — Principal Auditor Fees and Services” and “Ratification of Independent Auditors — Pre-Approval Policies and Procedures” in the Notice of the 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.


	(a)	The following documents are filed as part of this report: (1) Financial Statements:


	(2)	Financial Statement Schedules: We have included on page 31 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.


	(1)	A Current Report on Form 8-K was furnished by the company on October 31, 2003. In this report, ChevronTexaco furnished a press release announcing preliminary unaudited third quarter 2003 net income of $1.975 billion.

	(2)	A Current Report on Form 8-K was furnished by the company on January 30, 2004. In this report, ChevronTexaco furnished a press release announcing preliminary unaudited net income of $1.7 billion for the fourth quarter 2003 and $7.2 billion for the year.

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 9th day of March, 2004.


	By	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 9th day of March, 2004.

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

KEY FINANCIAL RESULTS


Millions of dollars, except per-share amounts		2003			2002			2001

Net Income		$	7,230		$	1,132		$	3,288
Per Share:
Net Income	– Basic	$	6.97		$	1.07		$	3.10
	– Diluted	$	6.96		$	1.07		$	3.09
Dividends*		$	2.86		$	2.80		$	2.65
Sales and Other
Operating Revenues		$	120,032		$	98,691		$	104,409
Return on:
Average Capital Employed			15.7	%		3.2	%		7.8	%
Average Stockholders’ Equity			21.3	%		3.5	%		9.8	%

*Chevron Corporation dividend pre-merger.

INCOME (LOSS) BY MAJOR OPERATING AREA BEFORE CHANGES IN ACCOUNTING PRINCIPLES


Millions of dollars	2003			2002			2001

Exploration and Production
United States	$	3,183		$	1,717		$	1,779
International		3,220			2,839			2,533

Total Exploration and Production		6,403			4,556			4,312

Refining, Marketing and Transportation
United States		482			(398	)		1,254
International		685			31			560

Total Refining, Marketing and Transportation		1,167			(367	)		1,814

Chemicals		69			86			(128	)
All Other		(213	)		(3,143	)		(2,710	)

Income Before Cumulative Effect of Changes in Accounting Principles	$	7,426		$	1,132		$	3,288
Cumulative Effect of Changes in Accounting Principles		(196	)		–			–

Net Income^*	$	7,230		$	1,132		$	3,288

^*Includes Foreign Currency (Losses) Gains:	$	(404	)	$	(43	)	$	191

Net income includes net charges of $196 million for the cumulative effect of changes in accounting principles, primarily $200 million for the adoption on January 1, 2003, of the Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). Refer to Note 25 to the Consolidated Financial Statements on page FS-50 for additional discussion. Also in the first quarter of 2003, the company recorded an after-tax gain of $4 million for its share of its affiliate Dynegy’s cumulative effect of adoption of Emerging Issues Task Force Consensus No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” effective January 1, 2003.

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

SPECIAL ITEMS


Millions of dollars – Income (loss)	2003			2002			2001

Dynegy-Related	$	325		$	(2,306	)	$	–
Asset Dispositions		122			–			49
Tax Adjustments		118			60			(5	)
Asset Impairments and Revaluations		(340	)		(485	)		(1,709	)
Restructuring and Reorganizations		(146	)		–			–
Environmental Remediation Provisions		(132	)		(160	)		(78	)
Merger-Related Expenses		–			(386	)		(1,136	)
Litigation Provisions		–			(57	)		–
Extraordinary Loss on Merger-Related Asset Sales		–			–			(643	)

Total Special Items	$	(53	)	$	(3,334	)	$	(3,522	)

Because of their nature and amount, these special items are identified separately to help explain the changes in net income and segment income between periods, as well as to help distinguish the underlying trends for the company’s 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 Reorganizations” is described in detail in Note 12 to the Consolidated Financial Statements on page FS-37. The categories “Merger-Related Expenses” and “Extraordinary Loss on Merger-Related Asset Sales” are described in detail in the “Texaco Merger Transaction” section on page FS-5.

BUSINESS ENVIRONMENT AND OUTLOOK

As shown in the “Special Items” table, large net special-item charges adversely affected net income in 2002 and 2001. In 2002, $2.3 billion of the $3.3 billion of net charges related to the company’s investment in its Dynegy Inc. affiliate. Refer to pages FS-10 and FS-11 for a discussion of these matters. Approximately one-half of the $3.5 billion of net charges in 2001 related to asset impairments, primarily the result of downward revisions to crude oil and natural gas reserve quantities.

Apart from the effects of special items, ChevronTexaco’s earnings depend largely on the profitability of its business segments in upstream – exploration and production – and downstream – refining, marketing and transportation. Overall earnings trends are typically less affected by results from the company’s commodity chemicals segment and other 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. The company also continuously evaluates opportunities to dispose of assets that are not key to providing long-term value, or 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, other such plans may occur in future periods and result in significant gains or losses. Refer to the “Operating Developments” section on pages FS-4 and FS-5 for a discussion that includes references to the company’s asset disposition activities.

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

Upstream Year-to-year changes in exploration and production earnings align most closely with industry price levels for crude oil and natural gas. Crude oil and natural gas prices are subject to certain external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, 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 uncertainties. The company monitors developments closely in the countries in which it operates.

Longer-term trends in earnings for this segment are also a function of other factors besides price fluctuations, including changes in the company’s oil and gas production levels and the company’s ability to find or acquire and efficiently produce crude oil and natural gas reserves. Most of the company’s overall capital investment is in its upstream businesses, particularly outside the United States. Refer to the “Capital and Exploratory Expenditures” on pages FS-11 and FS-12 for discussion of the types of upstream investments targeted for 2004. Investments in upstream projects oftentimes are made well in advance of the start of the associated crude oil and natural gas production.

Industry price levels for crude oil in early 2003 reached a 12-year high, reaching a peak of about $38 per barrel. Prices for West Texas Intermediate (WTI), a benchmark crude, then averaged about $31 for the year, an increase of about $5 from 2002. The WTI spot prices at the end of December 2003 and at the end of February 2004 were about $32 and $36, respectively. Among other things, these relatively high industry prices reflected increased demand from improved economies in many countries and continued production curtailments by OPEC.

(LINE GRAPH)

The average spot price of West Texas Intermediate, a benchmark crude oil, rose 19 percent between 2002 and 2003 and remained above $30 per barrel in early 2004.

Natural gas prices were also higher in 2003 than in 2002. Benchmark prices for Henry Hub U.S. natural gas averaged more than $5 per thousand cubic feet in 2003, versus about $3 in 2002. The 2003 year-end price was nearly $6 per thousand cubic feet, about a dollar higher than the year-earlier level. Prices in the United States are typically highest during the winter period, when demand for heating fuel is greatest. At the end of February 2004, the U.S. benchmark price was about $5 per thousand cubic feet. The trend toward higher U.S. natural gas prices is mainly the result of overall demand based upon the strength of

(BAR CHARTS)


Average prices climbed more than 70 percent during 2003. Production was down more than 7 percent due to normal field declines and production not restored after 2002 storm damage to facilities in the Gulf of Mexico.		Net liquids production declined about 5 percent in 2003, primarily the result of normal field declines in the United States. * Includes equity in affiliates

the economy and the declining levels of industry reserves and production in the United States.

Partially offsetting the benefit of higher crude oil and natural gas prices in 2003 was a 4 percent decline in the company’s worldwide oil-equivalent production from the prior year. The decrease was largely the result of lower production in the United States due to normal field declines and production deemed uneconomic to restore following storm damages in the Gulf of Mexico in the second half of 2002. International oil-equivalent production was also down slightly — primarily the result of lower liquids production in the company’s Indonesian operations. The reduced net production in Indonesia was mainly due to the effect of higher prices on cost-oil recovery volumes under production-sharing arrangements and the expiration of a production-sharing agreement in the third quarter 2002.

The company’s oil-equivalent production level in future periods is uncertain, in part because of production quotas set by OPEC and the potential for production disruptions from civil unrest and changing geopolitics in the countries in which the company operates and holds interests. Twenty-two percent of the company’s net oil equivalent production in 2003 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 levels in these areas were not constrained in 2003 by OPEC quotas, future production could be affected by OPEC-imposed limitations. In Nigeria, about 45,000 barrels per day of the company’s net production capacity has been shut-in in certain onshore areas since March 2003 because of security concerns. The company expects to re-enter this area during 2004 to begin repairing damaged equipment. OPEC production constraints could possibly limit the eventual resumption of a portion or all of this production.

Downstream Refining, marketing and transportation earnings are closely tied to regional supply and demand for refined products and the associated effects on industry refining and marketing margins. The company’s core marketing areas are the western and southeastern United States, western Canada, the Asia-Pacific, northern Europe, Africa and Latin America.

Company-specific factors influencing the company’s profitability in this segment include the operating efficiencies of the refinery network, including any downtime due to planned maintenance, refinery upgrade projects or operating incidents.

Downstream earnings improved in 2003, compared with the prior year, on higher refined product margins in most of the company’s operating areas. In contrast, margins in the 2002 period were at their lowest levels since the mid-1990s, as weak market conditions did not allow rising feedstock costs to be fully recovered from consumers of refined products. Industry margins may be volatile in the future, depending primarily on price movements for crude oil feedstocks, the strength of the economies in which the company operates and other factors.

Chemicals Earnings of $69 million in 2003 were lower than the year-ago period. Depressed earnings in both years reflected excess-supply conditions for the commodity chemicals industry that have kept product margins at low levels for a protracted period. A significant improvement in earnings is not expected in the near future.

OPERATING DEVELOPMENTS

Key operating developments and events during 2003 and early 2004 included:

Upstream
Worldwide Oil and Gas Reserves Approximately 1 billion barrels of oil-equivalent reserves were added during 2003, including sales and acquisitions. These additions equated to 108 percent of production for the




Net proved reserves additions in 2003 equaled 108 percent of oil-equivalent production for the period. This was the 11th consecutive year that reserve additions exceeded 100 percent of production.

* Barrels of oil-equivalent ** Includes equity in affiliates

year. Of the 1 billion barrels added, nearly 300 million were the result of discoveries and extensions, including almost 200 million in the United States. Contract extensions in Colombia and Denmark accounted for approximately 200 million additional barrels. About 100 million barrels were added through improved recovery techniques, primarily in Indonesia and the United States. Finally, the largest revisions resulted from reservoir studies and analyses in Kazakhstan, increasing reserves 300 million barrels.

North America Plans were initiated to improve the competitive performance and operating efficiency of the company’s North America exploration and production portfolio. These plans include the sale of certain nonstrategic producing properties and royalty interests in the United States and possibly western Canada. The company expects to retain about 400 core fields. Additionally, the company expects to consolidate certain business functions and office locations.

In late 2003, four new deepwater discoveries in the Gulf of Mexico — Perseus, Sturgis, Tubular Bells and Saint Malo — were announced.

ChevronTexaco is the operator and holds a 50 percent working interest in both the Perseus and Sturgis prospects. In the non-operated discoveries, the company holds a 30 percent interest in Tubular Bells and a 12.5 percent interest in Saint Malo. Additionally at the Blind Faith discovery, an agreement was reached to assume operatorship and increase the company’s working interest to 50 percent.

At the Tahiti prospect, a major discovery in the deepwater Gulf of Mexico, appraisal drilling validated the presence of high-quality reservoir sand. ChevronTexaco is the operator of the prospect and has a 58 percent working interest.

In late 2003, an appraisal well was drilled at the Great White discovery, a nonoperated exploratory opportunity in the western Gulf of Mexico. The company has a 33 percent working interest in this prospect.

Australia A well was drilled during 2003 in the Io-Jansz natural gas field, off the northwest coast of Western Australia. Test results provided verification of the field’s extensive production potential. ChevronTexaco holds a 50 percent equity interest in the WA-18-R permit area.

Nigeria In October 2003, successful results were announced from the Aparo-3 appraisal well and the Nsiko-1 wildcat well in deepwater Block OPL-249, where the company is entitled to a variable equity interest over the life of the field. In addition, the company announced a significant extension of its 30 percent-owned Usan Field discovery. The drilling of the Usan-4 appraisal well, located in deepwater Block OPL-222, confirmed the presence of commercial quantities of oil as well as additional potential in previously untested reservoirs. In early 2003, the company announced a gas discovery in the 46 percent-owned deepwater Block OPL-218, following completion of the Nnwa-2 appraisal well.

Earlier in the year, the company and its partners reached an agreement that will govern future operations in the offshore Block OPL-216 concession. The agreement is expected to enable the continued advancement of plans to develop the Agbami Field. The company has varying funding obligations and profit entitlement for the Block OPL-216 development according to the terms of two production-sharing contracts in the concession.

Angola Major contracts were awarded for the first phase of development in the Benguela, Belize, Lobito and Tomboco fields in deepwater Block 14. The first phase will involve the drilling and completion of more than 30 development wells in the Benguela and Belize fields and the construction and installation of drilling and production facilities that will form a new production hub in Block 14. The company is the operator and holds a 31 percent interest in Block 14.

Chad/Cameroon The company’s first cargo of crude oil from fields in southern Chad was loaded at facilities offshore Cameroon for export to world markets in late 2003. The crude oil produced in Chad is transported more than 600 miles by pipeline to a floating storage and offloading vessel located several miles offshore. Full production capacity of 225,000 barrels per day is expected to be reached in mid-2004. ChevronTexaco holds a 25 percent equity interest in the Chad-Cameroon upstream operation and about a 23 percent interest in the pipeline.

Kazakhstan The company’s 50 percent-owned affiliate, Tengiz-chevroil (TCO) reached an agreement with the government of

Kazakhstan in the third quarter of 2003 to expand operations at the Tengiz and Korolev fields. The Sour Gas Injection/Second Generation project is expected to increase TCO’s oil production capacity from 285,000 barrels per day to between 430,000 and 500,000 barrels per day in the second half of 2006. Also, a 400-mile pipeline was completed that will enable production from the Karachaganak Field to be exported to world markets via the Caspian Pipeline when fully operational in mid-2004.

Colombia An agreement was reached that extends the company’s production rights in northern natural gas fields. Under the contract extension, ChevronTexaco holds a 43 percent interest with the remaining 57 percent held by the country’s national petroleum company.

Venezuela ChevronTexaco was awarded the license for the 60 percent-owned and -operated Block 2 Plataforma Deltana, a prospective natural gas region in Venezuela’s Atlantic continental shelf.

Global Natural Gas Projects In the Gulf of Mexico, the company’s permit application was approved for plans to develop the Port Pelican deepwater LNG facility. The company also filed permits for the construction of a LNG receiving and regasification terminal offshore Baja California, Mexico.

In September 2003, the Gorgon Joint Venture, in which the company is a 57 percent owner, received in-principle approval from the Western Australian government through an act of parliament to proceed with plans to construct a natural gas processing facility on Barrow Island. The decision represented a significant milestone in the company’s plans to commercialize its large Gorgon natural gas resource base. Also in 2003, the Gorgon Joint Venture announced an agreement with the China National Offshore Oil Corporation (CNOOC) in October to negotiate the sale of Gorgon liquefied natural gas to the People’s Republic of China. The agreement, which is subject to the completion of formal contracts, enables CNOOC to purchase an interest in the Gorgon gas development project and to facilitate the sale of LNG into the Chinese market.

In Nigeria, the company and its partners in the Brass River Consortium agreed to advance plans for the front-end engineering and design work for a new LNG facility at Brass River. The studies are expected to be completed in 2004.

A new U.S. wholesale natural gas marketing unit became fully operational in April 2003. This business unit was established following a decision by the company’s Dynegy affiliate to exit the natural gas marketing and trading business. ChevronTexaco’s natural gas sale and purchase agreements with Dynegy were terminated at the end of January 2003.

Downstream

The company initiated a major restructuring of its global refining, marketing, and supply and trading organizations in order to lower costs, improve efficiency and achieve sustained improvements in its financial performance relative to competitors. The organization was changed from a geographical to a global functional alignment and was implemented at the beginning of 2004.

Downstream asset dispositions, including the sale of the El Paso, Texas, refinery and approximately 400 service stations in various markets, were completed in 2003 to improve returns by

focusing investment in areas with the strongest long-term growth and returns.

Facility upgrade projects at refineries in Pascagoula, Mississippi; Pembroke, United Kingdom; and Rotterdam, Netherlands were completed, resulting in increased product yields and enabling the manufacture of low-sulfur fuels. In the Philippines, the Batangas Refinery was converted into a finished-product terminal.

Chemicals

In Qatar, a new olefins and polyolefins complex was commissioned in 2003. The complex is owned and operated through a joint venture between the company’s 50 percent-owned equity affiliate, Chevron Phillips Chemical Company (CPChem), and Qatar General Petroleum. CPChem holds a 49 percent interest in the joint venture.

TEXACO MERGER TRANSACTION

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

Merger Effects Under mandate of the Federal Trade Commission (FTC) as a condition to its approval of the merger, the company sold its interests in Equilon and Motiva – joint ventures engaged in U.S. downstream businesses – in February 2002, resulting in cash proceeds of $2.2 billion. Indemnification by ChevronTexaco against certain Equilon and Motiva contingent liabilities at the date of sale are discussed in the “Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies” section beginning on page FS-13. Other mandated asset dispositions were also completed during 2002. Net income and cash proceeds from these other asset sales were not material. All such assets sold as a result of the merger provided net income of approximately $375 million in 2001. The net loss on assets sold under the FTC mandate is presented in the 2001 income statement as an extraordinary item.

The company incurred before-tax merger-related expenses of approximately $1.6 billion ($1.1 billion after tax) and $576 million ($386 million after tax) in 2001 and 2002, respectively. Major expenses included employee severance payments; incremental pension and medical plan benefit costs associated with workforce reductions; legal, accounting, Securities and Exchange Commission (SEC) filing and investment banker fees; employee and office relocations; and costs for the elimination of redundant

facilities and operations. No significant merger-related expenses occurred in 2003.

RESULTS OF OPERATIONS

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

U.S. Exploration and Production


Millions of dollars	2003			2002			2001

Income Before Cumulative Effect of Change in Accounting Principle	$	3,183		$	1,717		$	1,779
Cumulative Effect of Accounting Change		(350	)		—			—

Segment Income	$	2,833		$	1,717		$	1,779

Special Items Included in Segment Income:
Asset Dispositions	$	77		$	—		$	49
Asset Impairments and Revaluations		(103	)		(183	)		(1,168	)
Restructuring and Reorganizations		(38	)		—			—
Environmental Remediation Provisions		—			(31	)		—
Tax Adjustments		—			—			8

Total Special Items	$	(64	)	$	(214	)	$	(1,111	)

The improvement in 2003 segment income from 2002 primarily was the result of higher prices for crude oil and natural

(BAR CHARTS)


Exploration expenses declined after the October 2001 merger, reflecting, in part, the high-grading of the combined exploration portfolio.		Earnings increased significantly in 2003 on higher prices for crude oil and natural gas. Partially offsetting were the effects of lower production and foreign currency losses. * Before the cumulative effect of changes in accounting principles

gas. Partially offsetting this effect was a decline in oil-equivalent production. The change between 2001 and 2002 reflected significantly lower natural gas realizations and lower production in the 2002 period.

The company’s average 2003 U.S. liquids realization was $26.66 per barrel, compared with $21.34 in 2002 and essentially the same in 2001. The average natural gas realization was $5.01 per thousand cubic feet in 2003, compared with $2.89 and $4.38 in 2002 and 2001, respectively.

Net oil-equivalent production averaged 933,000 barrels per day in 2003, down 7 percent from 2002 and 12 percent from 2001. The net liquids component for 2003 averaged 562,000 barrels per day, a decline of 7 percent from 2002 and 8 percent from 2001. Net natural gas production averaged 2.228 billion cubic feet per day in 2003, 7 percent lower than 2002 and 18 percent lower than 2001. The oil-equivalent production decline in 2003 was associated mainly with normal field declines and the absence of about 10,000 to 15,000 barrels per day of production the company deemed uneconomic to restore following storm damages in the Gulf of Mexico in late 2002. The storms reduced the company’s 2002 oil-equivalent production by about 20,000 barrels per day.

Net special-item charges of $64 million in 2003 reflected asset impairments of $103 million — associated mainly with the write-down of assets in anticipation of sale — and restructuring and reorganization charges of $38 million, which mainly were associated with employee severance costs. Offsetting a portion of these charges were gains of $77 million from asset sales. Special items in 2002 and 2001 included asset impairments caused by write-downs in proved oil and gas reserve quantities for a number of fields. The amount in 2001 related primarily to the Midway Sunset Field in California’s San Joaquin Valley, after the determination that lower-than-projected heavy oil recovery would result from the steam-injection process.

International Exploration and Production


Millions of dollars	2003			2002			2001

Income Before Cumulative Effect of Change in Accounting Principle*	$	3,220		$	2,839		$	2,533
Cumulative Effect of Accounting Change		145			—			—

Segment Income	$	3,365		$	2,839		$	2,533

*Includes Foreign Currency (Losses) Gains:	$	(319	)	$	90		$	181
Special Items Included in Segment Income:
Asset Dispositions	$	32		$	—		$	—
Asset Impairments and Revaluations		(30	)		(100	)		(247	)
Restructuring and Reorganizations		(22	)		—			—
Tax Adjustments		118			(37	)		(125	)

Total Special Items	$	98		$	(137	)	$	(372	)

The earnings improvement from 2002 to 2003 included the benefit of higher crude oil and natural gas prices. Partially offsetting the improvements were the effects of lower oil-equivalent production and an unfavorable swing in foreign currency effects. Net foreign currency losses of $319 million in 2003 primarily related to a significant weakening of the U.S. dollar against the

currencies of Canada, Australia and the United Kingdom. Earnings improvement in 2002 vs. 2001 were marginally affected by a combination of factors, including benefits from higher liquids realizations, higher natural gas production, and lower exploration and income tax expenses, which were offset in part by the effects of lower liquids production, lower natural gas realizations and higher depreciation expense.

The average liquids realization, including equity affiliates, was $26.79 per barrel in 2003, compared with $23.06 in 2002 and $22.17 in 2001. The average natural gas realization was $2.64 per thousand cubic feet in 2003, compared with $2.14 in 2002 and $2.36 in 2001.

Daily net liquids production of 1.246 million barrels in 2003 decreased about 4 percent from 1.295 million barrels in 2002 and about 7 percent from 1.345 million barrels in 2001. The 2003 production decline included about 29,000 barrels per day in Indonesia, related primarily to the effect of lower cost-oil recovery volumes under production-sharing terms during 2003, and the expiration of a production-sharing arrangement in the third quarter 2002. New production occurred in Chad in 2003 and higher volumes were produced in the United Kingdom and Venezuela. The 2002 production decline from the prior year included lower output in Indonesia, primarily due to changes in contractual terms, and in Nigeria, which was mainly associated with OPEC constraints. These effects were partially offset by increased production in Kazakhstan.

Net natural gas production of 2.064 billion cubic feet per day in 2003 was up 5 percent from 2002 and more than 20 percent from 2001. During 2003, output was higher in Australia, Kazakhstan, the Philippines and the United Kingdom. In 2002, areas with production increases from 2001 included the Philippines, Kazakhstan, Nigeria and Australia.

Special items in 2003 were composed of benefits totaling $150 million related to income taxes and property sales, partially offset by asset impairments and charges for employee termination costs. In 2002, special items included asset impairments connected with write-downs in quantities of proved oil and gas reserves for fields in Africa and Canada. In 2001, special items included a $247 million impairment of the LL-652 Field in Venezuela.

U.S. Refining, Marketing and


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)


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


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		5
	Petroleum — Exploration and Production		6
	Liquids and Natural Gas Production		6
	Acreage		7
	Reserves and Contract Obligations		8
	Development Activities		9
	Exploration Activities		10
	Review of Ongoing Exploration and Production Activities in Key Areas		11
	Petroleum — Natural Gas and Natural Gas Liquids		17
	Petroleum — Refining		17
	Petroleum — Refined Products Marketing		18
	Petroleum — Transportation		20
	Chemicals		21
	Coal		21
	Other Activities — Synthetic Crude Oil		21
	Global Power Generation		22
	Worldwide Gasification Technology		22
	Gas-to-Liquids		22
	Research and Technology		22
	Environmental Protection		22
	Web Site Access to SEC Reports		23
2.	Properties		24
3.	Legal Proceedings		24
4.	Submission of Matters to a Vote of Security Holders		24
	Executive Officers of the Registrant at March 1, 2004.		25
	PART II
5.	Market for the Registrant’s Common Equity and Related Stockholder Matters		26
6.	Selected Financial Data		26
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
7A.	Quantitative and Qualitative Disclosures About Market Risk		27
8.	Financial Statements and Supplementary Data		27
9.	Changes in and Disagreements with Auditors on Accounting and Financial Disclosure		27
9A.	Controls and Procedures		27
	PART III
10.	Directors and Executive Officers of the Registrant		28
11.	Executive Compensation		28
12.	Security Ownership of Certain Beneficial Owners and Management		28
13.	Certain Relationships and Related Transactions		28
14.	Principal Auditor Fees and Services		29
	PART IV
15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K		30
	Schedule II — Valuation and Qualifying Accounts		31
	Signatures		32
EXHIBIT 10.3
EXHIBIT 12.1
EXHIBIT 21.1
EXHIBIT 23.1
EXHIBIT 24.1
EXHIBIT 24.2
EXHIBIT 24.3
EXHIBIT 24.4
EXHIBIT 24.5
EXHIBIT 24.6
EXHIBIT 24.7
EXHIBIT 24.8
EXHIBIT 24.9
EXHIBIT 24.10
EXHIBIT 24.11
EXHIBIT 24.12
EXHIBIT 24.13
EXHIBIT 24.14
EXHIBIT 24.15
EXHIBIT 24.16
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2
EXHIBIT 99.1



									Developed and
	Undeveloped²				Developed²				Undeveloped

	Gross		Net		Gross		Net		Gross		Net

United States		8,080		6,027		7,901		3,923		15,981		9,950

Africa		22,328		7,797		683		200		23,011		7,997
Asia-Pacific		35,830		18,371		2,216		869		38,046		19,240
Other International		36,963		19,874		2,709		1,126		39,672		21,000

Total International		95,121		46,042		5,608		2,195		100,729		48,237

Total Consolidated Companies		103,201		52,069		13,509		6,118		116,710		58,187
Equity in Affiliates		1,062		504		89		39		1,151		543

Total Including Affiliates		104,263		52,573		13,598		6,157		117,861		58,730



	Productive¹				Productive¹
	Oil Wells				Gas Wells

	Gross²		Net²		Gross²		Net²

United States		53,617		31,535		12,515		6,486

Africa		1,729		620		11		5
Asia-Pacific		8,400		7,482		281		148
Other International		2,568		1,703		430		176

Total International		12,697		9,805		722		329

Total Consolidated Companies		66,314		41,340		13,237		6,815
Equity in Affiliates		217		76		—		—

Total Including Affiliates		66,531		41,416		13,237		6,815

Multiple completion wells included above:		925		642		627		504

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

		2003		2002		2003		2002		2003		2002

United States:
	California		231		243		112		125		250		264
	Gulf of Mexico		189		204		1,059		1,152		365		396
	Texas		84		89		463		508		161		174
	Wyoming		10		12		179		199		40		45
	Other States		48		54		415		421		117		124

Total United States			562		602		2,228		2,405		933		1,003

Africa:
	Angola		154		164		—		—		154		164
	Chad		8		—		—		—		8		—
	Nigeria		123		127		50		74		131		139
	Republic of Congo		13		16		—		—		13		16
	Democratic Republic of Congo		9		8		—		—		9		8
Asia-Pacific:
	Indonesia		223		263		166		147		251		288
	Partitioned Neutral Zone (PNZ)³		134		140		15		15		136		142
	Australia		48		52		284		264		95		96
	China		23		27		—		—		23		27
	Kazakhstan		25		22		101		85		42		36
	Thailand		25		18		104		87		42		33
	Philippines		8		7		140		105		31		25
	Papua New Guinea⁴		4		6		—		—		4		6
Other International:
	United Kingdom		116		113		378		361		179		173
	Canada		73		70		110		140		91		93
	Argentina		52		55		74		71		65		67
	Denmark		42		42		99		102		59		59
	Norway		10		15		—		3		10		16
	Venezuela		5		4		21		7		9		4
	Colombia		—		—		206		222		35		37
	Trinidad and Tobago		—		—		116		107		19		18

Total International			1,095		1,149		1,864		1,790		1,406		1,447

Total Consolidated Operations			1,657		1,751		4,092		4,195		2,339		2,450
	Equity in Affiliates⁵		151		146		200		181		184		176

Total Including Affiliates^{6, 7}			1,808		1,897		4,292		4,376		2,523		2,626



	Net Additions to												Memo: BOE
	Reserves					Net Production							Replacement %
													Excluding
	Liquids		Gas			Liquids		Gas		BOE			Sales and
	(MMBBLS)¹		(BCF)²			(MMBBLS)¹		(BCF)²		Replacement %³			Acquisitions³

United States		146		(251	)		205		813		31	%		40	%
Africa		59		362			112		18		104	%		104	%
Asia-Pacific		78		1,025			179		296		109	%		127	%
Other International⁴		308		1,286			164		439		220	%		212	%

Total Worldwide		591		2,422			660		1,566		108	%		114	%



					Net Wells Completed¹

	Wells Drilling at
	12/31/03				2003				2002				2001

	Gross²		Net²		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States		48		25		697		18		638		16		866		21

Africa		7		3		24		—		27		—		22		—
Asia-Pacific		30		2		605		—		470		—		555		—
Other International		11		4		107		—		140		—		109		2

Total International		48		9		736		—		637		—		686		2

Total Consolidated Companies		96		34		1,433		18		1,275		16		1,552		23
Equity in Affiliates		9		3		18		—		20		—		17		—

Total Including Affiliates		105		37		1,451		18		1,295		16		1,569		23



					Net Wells Completed¹

	Wells Drilling
	at 12/31/03				2003				2002				2001

	Gross²		Net²		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States		24		9		27		10		57		22		101		32

Africa		—		—		3		1		6		1		8		2
Asia-Pacific		—		—		7		3		4		1		31		8
Other International		2		1		2		4		7		9		6		10

Total International		2		1		12		8		17		11		45		20

Total Consolidated Companies		26		10		39		18		74		33		146		52
Equity in Affiliates		—		—		—		—		4		—		14		—

Total Including Affiliates		26		10		39		18		78		33		160		52



		December 31, 2003				Refinery Inputs

				Operable
		Number		Capacity		2003		2002		2001


Locations

Pascagoula	Mississippi		1		325		301		329		332
El Segundo	California		1		260		242		251		213
Richmond	California		1		225		235		187		229
El Paso¹	Texas		—		—		36		61		61
Honolulu	Hawaii		1		54		52		53		54
Salt Lake City	Utah		1		45		40		43		44
Other²			2		96		45		55		50

Total Consolidated Companies — United States			7		1,005		951		979		983

Equity in Affiliates³	Various Locations		—		—		—		—		353

Total Including Affiliates — United States			7		1,005		951		979		1,336

Pembroke	United Kingdom		1		210		175		204		202
Cape Town	South Africa		1		112		72		74		71
Batangas⁴	Philippines		—		—		49		59		65
Colón⁵	Panama		—		—		—		27		54
Burnaby, B.C.	Canada		1		52		50		51		52
Escuintla⁵	Guatemala		—		—		—		11		16

Total Consolidated Companies — International			3		374		346		426		460
Equity in Affiliates	Various Locations		11		785		694		674		676

Total Including Affiliates — International			14		1,159		1,040		1,100		1,136

Total Including Affiliates — Worldwide			21		2,164		1,991		2,079		2,472


		Net Mileage¹

United States:
	Crude Oil²		1,891
	Natural Gas		1,916
	Petroleum Products		5,044

	Total United States		8,851

International:
	Crude Oil²		414
	Natural Gas		—
	Petroleum Products		220

	Total International		634

Worldwide			9,485



		U.S. Flag				Foreign Flag

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

Owned			3		0.8		2		1.9
Bareboat Charter			—		—		16		22.3
Time Charter*			—		—		14		9.6

	Total		3		0.8		32		33.8


Name and Age		Executive Office Held	Major Area of Responsibility

D. J. O’Reilly	57	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	57	Vice Chairman of the Board since 2002 Vice President from 1994 to 2001 President of Chevron Overseas Petroleum Inc. from 2000 to 2002 Executive Committee Member since 1997	Worldwide Exploration and Production Activities and Global Gas Activities
J. E. Bethancourt	52	Executive Vice President since 2003 Executive Committee Member since 2003	Technology, Chemicals, Coal, Health, Environment and Safety
C. A. James	49	Vice President and General Counsel since 2002 Executive Committee Member since 2002	Law
G. L. Kirkland	53	President of ChevronTexaco Overseas Petroleum Inc. since 2002 Vice President since 2000 President of Chevron U.S.A. Production Company from 2000 to 2002 Executive Committee Member from 2000 to 2001	Overseas Exploration and Production
S. Laidlaw	48	Executive Vice President since 2003 Executive Committee Member since 2003	Business Development
J. S. Watson	47	Vice President, Finance and Chief Financial Officer since 2000 Vice President since 1998 Executive Committee Member since 2000	Finance
R. I. Wilcox	58	President, ChevronTexaco Exploration Production Company since 2002 Vice President since 2002	North American Exploration and Production
P. A. Woertz	50	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


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
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
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, Finance and Chief Financial Officer, Chevron Corporation — 2000
R. I. Wilcox	-	Vice President and General Manager, Marine Transportation, Chevron Shipping Company — 1996
	-	General Manager, Asset Management, Chevron Nigeria Limited — 1999
	-	Chairman and Managing Director, Chevron Nigeria Limited — 2000
	-	Corporate Vice President and President, ChevronTexaco Exploration & Production Company — 2002
P. A. Woertz	-	President, Chevron International Oil Company — 1996
	-	Vice President, Logistics and Trading, Chevron Products Company — 1996
	-	President, Chevron Products Company — 1998


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


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


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


(b)	Description of Business and Properties


		2003		2002		2001

United States
	Gasolines		669		680		709
	Jet Fuel		314		352		424
	Gas Oils and Kerosene		196		259		245
	Residual Fuel Oil		202		177		183
	Other Petroleum Products²		133		132		122

	Total United States		1,514		1,600		1,683

International
	Gasolines		543		519		533
	Jet Fuel		186		164		185
	Gas Oils and Kerosene		623		619		702
	Residual Fuel Oil		324		329		503
	Other Petroleum Products²		47		57		75
	Share of Affiliates’ Sales		501		487		456

	Total International		2,224		2,175		2,454

Total Worldwide			3,738		3,775		4,137


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


Item 7A.	Quantitative and Qualitative Disclosures About Market Risk


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


	Page(s)

Report of Independent Auditors — PricewaterhouseCoopers LLP		FS-21
Consolidated Statement of Income for the three years ended December 31, 2003		FS-22
Consolidated Statement of Comprehensive Income for the three years ended December 31, 2003		FS-23
Consolidated Balance Sheet at December 31, 2003 and 2002		FS-24
Consolidated Statement of Cash Flows for the three years ended December 31, 2003		FS-25
Consolidated Statement of Stockholders’ Equity for the three years ended December 31, 2003		FS-26 to FS-27
Notes to Consolidated Financial Statements		FS-28 to FS-50



	Year ended December 31

	2003			2002			2001

Employee Termination Benefits:
Balance at January 1	$	336		$	665		$	7
Additions charged to expense		295			71			763
Payments		(290	)		(400	)		(105	)

Balance at December 31	$	341		$	336		$	665

Other Merger-Related Expenses:
Balance at January 1	$	46		$	127		$	—
(Deductions) additions (credited) charged to expense		(6	)		(11	)		128
Payments		(10	)		(70	)		(1	)

Balance at December 31	$	30		$	46		$	127

Allowance for Doubtful Accounts:
Balance at January 1	$	225		$	183		$	136
Additions charged to expense		52			131			116
Bad debt write-offs		(48	)		(89	)		(69	)

Balance at December 31	$	229		$	225		$	183

Deferred Income Tax Valuation Allowance:*
Balance at January 1	$	1,740		$	1,512		$	1,574
Additions charged to deferred income tax expense		375			776			339
Deductions credited to deferred income tax expense		(562	)		(548	)		(401	)

Balance at December 31	$	1,553		$	1,740		$	1,512

* See also Note 16 to the Consolidated Financial Statements on pages FS-40 and FS-41.

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

Balance at December 31	$	—		$	—		$	—


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


Management’s Discussion and Analysis of Financial Condition and Results of Operations		FS-2 to FS-20
Report of Management		FS-21
Report of Independent Auditors		FS-21
Consolidated Statement of Income		FS-22
Consolidated Statement of Comprehensive Income		FS-23
Consolidated Balance Sheet		FS-24
Consolidated Statement of Cash Flows		FS-25
Consolidated Statement of Stockholders’ Equity		FS-26 to FS-27
Notes to Consolidated Financial Statements		FS-28 to FS-50
Quarterly Results and Stock Market Data		FS-51
Five-Year Financial Summary		FS-52
Supplemental Information on Oil and Gas Producing Activities		FS-52 to FS-59