CHEVRONTEXACO CORP - 10-K Annual Report

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 Transportation


Millions of dollars	2003			2002			2001

Segment Income (Loss)	$	482		$	(398	)	$	1,254

Special Items Included in Segment Income:
Asset Dispositions	$	37		$	—		$	—
Asset Impairments and Revaluations		—			(66	)		—
Environmental Remediation Provisions		(132	)		(92	)		(78	)
Restructuring and Reorganizations		(28	)		—			—
Litigation Provisions		—			(57	)		—

Total Special Items	$	(123	)	$	(215	)	$	(78	)

The U.S. refining, marketing and transportation earnings in 2003 reflected primarily a recovery in industry margins for refined products, especially on the West Coast. Margins in 2002 were very depressed and at one point, hovered near their 12-year lows. Results for 2001 included earnings of $375 million associated with assets that were later sold as a condition of the merger, which included the company’s Equilon and Motiva joint ventures.

Sales volumes for refined products of 1.514 million barrels per day in 2003 decreased about 5 percent from 2002. Demand was weaker for branded gasoline, diesel and jet fuels, and there were lower sales under certain supply contracts. Branded gasoline

(BAR CHARTS)


Refined products sales volumes decreased about 5 percent from 2002. The decline partially reflected the August 2003 sale of the El Paso, Texas, refinery. * Includes equity in affiliates		U.S. downstream earnings in 2003 rebounded from a loss in 2002, primarily due to a recovery in the industry margins for refined products.

sales volumes of 557,000 barrels per day were 4 percent lower than 2002. In 2002, branded gasoline sales increased approximately 4 percent compared with 2001 volumes. The average U.S. refined products sales realization of $39.93 per barrel in 2003 was up from the average of $32.63 per barrel and $36.26 per barrel in 2002 and 2001, respectively.

Special items in 2003 included $160 million for reserves for environmental remediation and employee severance costs associated with the global downstream restructuring and reorganization. These charges were partially offset by gains primarily from the sale of service stations. In 2002, special items included environmental remediation provisions and asset write-downs for certain refining and marketing assets, and a litigation charge.

International Refining, Marketing and Transportation


Millions of dollars	2003			2002			2001

Segment Income*	$	685		$	31		$	560

*Includes Foreign Currency (Losses) Gains:	$	(141	)	$	(176	)	$	23
Special Items Included in Segment Income:
Asset Dispositions	$	(24	)	$	—		$	—
Asset Impairments and Revaluations		(123	)		(136	)		(46	)
Restructuring and Reorganizations		(42	)		—			—
Tax Adjustments		—			—			8

Total Special Items	$	(189	)	$	(136	)	$	(38	)

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

As in the United States, the international downstream earnings increased on improved refined-product margins for the industry. The decline in earnings from 2001 to 2002 reflected not only the trend in refined product margins but also about a $200 million unfavorable shift in foreign currency effects between periods.

Total international refined products sales volumes were 2.224 million barrels per day in 2003, up about 2 percent from

(GRAPHS)


Refined products sales volumes increased about 2 percent from 2002. *Includes equity in affiliates		Protracted weak demand for commodity chemicals and industry oversupply continue to suppress chemical earnings. *Includes equity in affiliates

2.175 million in 2002 and about 9 percent lower than 2.454 million in 2001. Weak economic conditions dampened demand in 2002.

Special items of $189 million in 2003 included charges for the write-down of the Batangas Refinery in the Philippines in advance of its conversion to a product terminal facility and employee severance benefits associated with the global downstream restructuring and reorganization. In addition, special charges of $70 million were recognized for the impairment of assets in anticipation of their sale and the company’s share of losses from an asset sale and asset impairment by an equity affiliate. The special item in 2002 was for a write-down of the company’s investment in its publicly traded Caltex Australia Limited affiliate to its estimated fair value.

Chemicals


Millions of dollars	2003		2002		2001

Segment Income (Loss) *	$	69	$	86	$	(128	)

* Includes Foreign Currency Gains (Losses):	$	13	$	3	$	(3	)
Special Items Included in Segment Income:
Asset Impairments and Revaluations	$	—	$	—	$	(96	)

Chemicals includes the company’s Oronite division and equity earnings from the company’s 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate. Protracted weak demand for commodity chemicals and industry oversupply conditions continued to suppress earnings for this sector. Special items in 2001 included write-downs of the CPChem Puerto Rico operations.

All Other


Millions of dollars	2003			2002			2001

Charges Before Cumulative Effect of Change in Accounting Principles*	$	(213	)	$	(3,143	)	$	(2,710	)
Cumulative Effect of Accounting Changes		9			—			—

Segment Charges*	$	(204	)	$	(3,143	)	$	(2,710	)

* Includes Foreign Currency Gains (Losses):	$	43		$	40		$	(10	)
Special Items Included in Segment Charges:
Dynegy-Related	$	325		$	(2,306	)	$	—
Asset Impairments and Revaluations		(84	)		—			(152	)
Restructuring and Reorganizations		(16	)		—			—
Tax Adjustments		—			97			104
Environmental Remediation Provisions		—			(37	)		—
Merger-Related Expenses		—			(386	)		(1,136	)
Extraordinary Loss on Merger-Related Asset Sales		—			—			(643	)

Total Special Items	$	225		$	(2,632	)	$	(1,827	)

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

The change in net charges between 2002 and 2003 was largely attributable to the differences in the effects of special items. The 2003 period also included lower interest expense and other corporate charges compared with 2002. Aside from the effect of special items between 2001 and 2002, the net change also reflected lower corporate charges and net interest expense, as well as an increase in favorable tax adjustments of $245 million.

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

Special items in 2002 included $2.3 billion related to Dynegy, composed of $1.6 billion for the write-down of the company’s investment in Dynegy common and preferred stock to its estimated fair value and $680 million for the company’s share of Dynegy’s own special items for asset write-downs and revaluations and a loss on an asset sale. Refer also to pages FS-10 and FS-11 for “Information Relating to the Company’s Investment in Dynegy.”

Refer to “Texaco Merger Transaction” on page FS-5 for information related to special items in 2001 for “Merger-Related Expenses” and “Extraordinary Loss from Merger-Related Asset Sales.”

Consolidated Statement of Income In the following table, amounts for special items by income statement category are shown in order to assist in the explanation of changes in those categories between periods. In addition to the effects of special items shown in the table, separately disclosed on the face of the Consolidated Income Statement are a 2003 gain from the exchange of Dynegy Inc. securities, merger-related expenses,

write-down of investments in Dynegy Inc., the cumulative effect of changes in accounting principles and the extraordinary after-tax loss on the sale of assets mandated as a condition of the merger. These matters are discussed elsewhere in MD&A and in Notes 2 and 14 to the Consolidated Financial Statements on pages FS-30 and FS-38.


Millions of dollars	2003			2002			2001

Income (loss) from equity affiliates	$	1,029		$	(25	)	$	1,144

Memo: Special gains (charges), before tax		179			(829	)		(123	)
Other income	$	335			247			692

Memo: Special gains, before tax		217			—			84
Operating expenses	$	8,553		$	7,848		$	7,650

Memo: Special charges, before tax		329			259			25
Selling, general and administrative expenses	$	4,440		$	4,155		$	3,984

Memo: Special charges, before tax		146			180			139
Depreciation, depletion and amortization	$	5,384		$	5,231		$	7,059

Memo: Special charges, before tax		286			298			2,294
Interest and debt expense	$	474		$	565		$	833

Memo: Special charges, before tax		—			—			—
Taxes other than on income	$	17,906		$	16,689		$	15,156

Memo: Special charges, before tax		—			—			12
Income tax expense	$	5,344		$	3,024		$	4,360

Memo: Special benefits		(312	)		(604	)		(1,193	)

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

Sales and other operating revenues were $120 billion in 2003, compared with $99 billion in 2002 and $104 billion in 2001. Revenues increased in 2003 primarily from significantly higher prices for crude oil, natural gas and refined products worldwide.

Total sales and operating revenues in 2002 declined from 2001 due to lower average realizations for crude oil and refined products, as well as lower prices and sales volumes for natural gas in the United States.

Income (loss) from equity affiliates increased in 2003, as earnings improved for a number of affiliates, including Tengiz-chevroil, LG-Caltex and CPChem. In 2001, income from equity affiliates included earnings from assets subsequently sold as a condition of the merger.

Other income in 2003 reflected significantly higher foreign currency losses. Likewise, foreign currency effects largely contributed to lower “Other income” in 2002 vs. 2001. Foreign currency losses in 2003 — excluding foreign currency gains or losses of affiliates which are included in “Income (loss) from equity affiliates” — were $199 million, compared with a loss of $5 million and a gain of $121 million in 2002 and 2001, respectively. In 2003, losses resulted primarily from the weakening of the U.S. dollar against the currencies of Canada, Australia and the United Kingdom. In 2002, foreign currency losses related to currencies of most countries in which the company has sig-

nificant operations appreciating against the U.S. dollar. Other income in 2002 also reflected lower interest income.

Purchased crude oil and products costs of $72 billion in 2003 increased about 25 percent from 2002. The increase was the result of significantly higher prices for crude oil, natural gas and refined products. Crude oil and products purchase costs decreased about 5 percent in 2002, primarily due to lower natural gas prices and reduced natural gas volumes.

Operating, selling, general and administrative expenses of $13 billion increased from $12 billion in 2002. About $800 million of the increase in 2003 resulted from higher freight rates from international shipping operations and higher costs of employee pension plans and other employee-benefit



		The 8 percent increase in 2003 resulted primarily from higher costs for transportation, shipping, pension plans and other employee benefits.

expenses. During 2002, operating, selling, general and administrative expenses increased approximately $95 million from 2001, primarily from higher pension expense, payroll and other employee- benefit costs. Refer to Note 21, “Employee Benefit Plans,” beginning on page FS-42 for discussion of the costs associated with the company’s pension plans and other employee benefits in the comparative periods.

Exploration expenses were $571 million in 2003, $591 million in 2002 and $1 billion in 2001. Well write-offs were higher in 2001 than in the other comparative periods.

Depreciation, depletion and amortization expenses did not change materially for the reporting periods after consideration of the effects from special items.

Merger-related expenses were $576 million and approximately $1.6 billion in 2002 and 2001, respectively. No merger-related expenses were recorded in 2003, reflecting the completion of merger integration activities in 2002.

Taxes other than on income were $17.9 billion, $16.7 billion and $15.2 billion in 2003, 2002 and 2001, respectively. The increase in 2003 primarily reflected the weakening U.S. dollar in 2003 on foreign-currency-denominated duties in the company’s European downstream operations. In 2002, the increase between periods resulted from higher sales volumes in the United Kingdom along with currency effects of a weaker U.S. dollar in the company’s European downstream operations.

Interest and debt expense was $474 million in 2003, compared with $565 million in 2002 and $833 million in 2001. The declines between periods reflected lower average interest rates on commercial paper and other variable rate debt and lower average debt levels.

Income tax expense corresponded to effective tax rates of 43 percent in 2003 and 45 percent in 2002 and 2001, after taking into account the effect of special items. See also Note 16 on pages FS-40 and FS-41, “Taxes,” in the Notes to the Consolidated Financial Statements.

SELECTED OPERATING DATA


	2003		2002		2001

U.S. Exploration and Production
Net Crude Oil and Natural Gas Liquids Production (MBPD)		562		602		614
Net Natural Gas Production (MMCFPD)¹		2,228		2,405		2,706
Net Production (MBOEPD)		933		1,003		1,065
Natural Gas Sales (MMCFPD)²		3,871		5,463		7,830
Natural Gas Liquids Sales (MBPD)²		194		241		185
Revenues from Net Production
Liquids ($/Bbl)	$	26.66	$	21.34	$	21.33
Natural Gas ($/MCF)	$	5.01	$	2.89	$	4.38
International Exploration and Production²
Net Crude and Natural Gas Liquids Production (MBPD)		1,246		1,295		1,345
Net Natural Gas Production (MMCFPD)¹		2,064		1,971		1,711
Net Production (MBOEPD)		1,590		1,623		1,630
Natural Gas Sales (MMCFPD)		1,951		3,131		2,675
Natural Gas Liquids Sales (MBPD)		107		131		115
Revenues from Liftings
Liquids ($/Bbl)	$	26.79	$	23.06	$	22.17
Natural Gas ($/MCF)	$	2.64	$	2.14	$	2.36
Other Produced Volumes (MBPD)³		114		97		105
U.S. Refining, Marketing and Transportation^2,4
Gasoline Sales (MBPD)		669		680		709
Other Refined Products Sales (MBPD)		845		920		974
Refinery Input (MBPD)		951		979		983
Average Refined Products Sales Price ($/Bbl)	$	39.93	$	32.63	$	36.26
International Refining, Marketing and Transportation²
Gasoline Sales (MBPD)		543		519		533
Other Refined Products Sales (MBPD)		1,681		1,656		1,921
Refinery Input (MBPD)		1,040		1,100		1,136
Average Refined Products Sales Price ($/Bbl)	$	46.64	$	37.18	$	48.90

¹ Includes natural gas consumed on lease:
United States		65		64		64
International		262		256		262
² Includes equity in affiliates, except as explained in footnote 4.
³ Other produced volumes includes:
Athabasca Oil Sands – net		15		–		–
Boscan Operating Service Agreement		99		97		105
⁴ Excludes Equilon and Motiva.

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

MBOEPD = Thousands of barrels of oil equivalents per day; Bbl = Barrel;

MCF = Thousands of cubic feet.

Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of gas = 1 barrel of oil.

INFORMATION RELATED TO INVESTMENT IN DYNEGY INC.

ChevronTexaco owns an approximate 26 percent equity interest in the common stock of 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.

Investment in Dynegy Common Stock At December 31, 2003, the carrying value of the company’s investment in Dynegy common stock was approximately $150 million. This amount was about $425 million below the company’s proportionate interest in Dynegy’s underlying net assets. This difference resulted from write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value that were deemed to be other than temporary. The approximate $425 million difference has been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors giving rise to the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and Dynegy’s historical book values. The market value of the company’s investment in Dynegy’s common stock at December 31, 2003, was $415 million.

Investments in Dynegy Notes and Preferred Stock At the beginning of 2003, the company held $1.5 billion aggregate principal amount of Dynegy Series B Preferred Stock, which was due for redemption at par value in November 2003. In August, the company exchanged its preferred stock for $225 million in cash, $225 million face value of Dynegy Junior Unsecured Subordinated Notes due 2016 and $400 million face value of Dynegy Series C Convertible Preferred Stock with a stated maturity of 2033.

The company recorded the Junior Notes and Series C Preferred Stock on the date of exchange at their fair values of $170 million and $270 million, respectively, for a total of $440 million. Together with the $225 million cash, the total amount recorded on the date of exchange was $665 million. A gain of $365 million was included in net income at that date for the difference between the $665 million fair value received and the net balance sheet amount of $300 million associated with the Series B shares.

At December 31, 2003, the estimated fair values of the Junior Notes and Series C shares totaled $530 million. The $90 million increase from the $440 million recorded in August was recorded to “Investments and Advances,” with an offsetting amount in “Other Comprehensive Income.” Future temporary changes in the estimated fair values of the new securities likewise will be reported in “Other Comprehensive Income.” However, if any future decline in fair value is deemed to be other than temporary, a charge against income in the period would be recorded. Interest that accrues on the notes and dividends payable on the preferred stock is recognized in income each period.

In addition to the $365 million gain recorded in income in the third quarter 2003, the company recorded $170 million directly to “Retained Earnings.” The latter amount represented the company’s approximate 26 percent equity share of a gain recorded by Dynegy in connection with the Series B exchange transaction. Under the accounting rules applicable to preferred

stock redemptions, ChevronTexaco increased its earnings per share in the third quarter 2003 by $0.16 for the effect of the $170 million recorded directly to “Retained Earnings.”

In February 2004, Dynegy announced agreement to sell its Illinois Power subsidiary to Ameren Corporation. The sale is conditioned upon, among other things, the receipt of approvals from governmental and regulatory agencies. Pending these approvals, the acquisition is expected to close in the fourth quarter of 2004. The sale of Illinois Power triggers a mandatory prepayment provision in the Dynegy Junior Notes held by the company. Under the terms of that provision, 75 percent of the net proceeds, not including any amounts used for the payment of any debt associated with Illinois Power, are to be used to retire at par, plus accrued interest, the $225 million face value notes.

LIQUIDITY AND CAPITAL RESOURCES

Cash, cash equivalents and marketable securities totaled $5.3 billion and $3.8 billion at December 31, 2003 and 2002, respectively. Cash provided by operating activities in 2003 was $12.3 billion, compared with $9.9 billion in 2002 and $11.5 billion in 2001. The 2003 increase in cash provided by operating activities mainly

(GRAPHS)


Higher earnings helped boost the company’s operating cash flow by 24 percent.		Interest expense fell 16 percent on significantly lower debt levels.

reflected higher earnings in the U.S. upstream and worldwide downstream businesses. Cash provided by asset sales was $1.1 billion in 2003, $2.3 billion in 2002 and about $300 million in 2001. In 2002, the company received proceeds of $2.2 billion, including dividends due, from the FTC-mandated sale of the company’s investments in Equilon and Motiva. Cash provided by operating activities during 2003 generated sufficient funds for the company’s capital and exploratory expenditure program and the payment of dividends to stockholders as well as contributing significantly to a reduction of $3.7 billion in debt levels, $1.4 billion funding of the company’s pension plans and the increase in cash and cash equivalents and marketable securities.

Dividends Payments of approximately $3 billion in 2003 and 2002 and $2.9 billion in 2001 were made for dividends or distributions for common stock, preferred stock and minority interests.

Debt, capital lease and minority interest obligations Chevron-Texaco’s total debt and capital lease obligations totaled $12.6 billion at December 31, 2003, down from $16.3 billion at year-end 2002. The company also had minority interest obligations of $268 million, down from $303 million at December 31, 2002.

The company’s debt and capital lease obligations due within one year, consisting primarily of commercial paper and the current portion of long-term debt, totaled $6 billion at December 31, 2003, down from $9.5 billion at December 31, 2002. Of these amounts, $4.3 billion and $4.1 billion, respectively, were reclassified to long-term at the end of each period. Settlement of the obligations at year-end 2003 was not expected to require the use of working capital in 2004, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis. The company’s practice has been to continually refinance its commercial paper, maintaining levels it believes appropriate.

At year-end 2003, ChevronTexaco had $4.3 billion in committed credit facilities with various major banks, which permit the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowings and also can be used for other general credit requirements. No borrowings were outstanding under these facilities during the year or at year-end 2003. In addition, the company had three existing effective “shelf” registrations on file with the Securities and Exchange Commission (SEC) that together would permit additional registered debt offerings up to an aggregate of $3.8 billion of debt securities.

In 2003, the company issued $1 billion of new long-term debt and other financing obligations, including $750 million of 3.375 percent ChevronTexaco Capital notes due in February 2008, $265 million of new Philippine debt and $19 million of individually smaller issues. Proceeds from the ChevronTexaco Capital Company note issue were used to retire commercial paper. Repayments of long-term debt included $665 million of Texaco Capital Inc. bonds, $143 million of Philippine debt, $110 million of ChevronTexaco Corporation 8.11 percent notes, $128 million of Nigerian debt and $91 million of individually smaller issues. Additionally, a $210 million payment was made to the Republic of Kazakhstan relating to the company’s 1993 acquisition of its interest in the TCO joint venture. Also included in the company’s long-term debt levels was a noncash reduction of $50 million of ESOP debt.

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

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

Capital and exploratory expenditures for 2003 totaled $7.4 billion, including the company’s equity share of affiliates’ expenditures. Capital and exploratory expenditures were $9.3 billion in 2002 and $12 billion in 2001. ChevronTexaco’s equity share of affiliates’ expenditures were $1.1 billion, $1.4 billion and $1.7 billion in 2003, 2002 and 2001, respectively, and did not require cash outlays by the company. Expenditures of $5.7 billion in



		International projects accounted for 71 percent of worldwide exploration and production expenditures in 2003. *Includes equity in affiliates

2003 for exploration and production activities represented 77 percent of total outlays for the year, compared with 68 percent in 2002 and 59 percent in 2001. International exploration and production spending of $4.0 billion was 71 percent of worldwide exploration and production expenditures in 2003, compared with 70 percent in 2002 and 66 percent in 2001, reflecting the company’s continuing focus on international exploration and production activities.

Expenditures in 2003 were $1.9 billion lower than the prior year, primarily due to amounts spent in 2002 for large lease acquisitions in the North Sea and the Gulf of Mexico, the Athabasca Oil Sands Project in western Canada, and additional common stock investments in Dynegy. The largest expenditures in 2003 included upstream projects in Eurasia, West Africa and the Gulf of Mexico. Expenditures in 2002 included lower additional investments in equity

affiliates than in 2001 due to the absence of the company’s share of expenditures for its Equilon and Motiva investments, which were sold as a condition of the merger. The 2001 expenditures included additional investments in TCO and Dynegy, including the purchase of $1.5 billion of Dynegy preferred stock.

Including the share of spending by affiliates, the company estimates 2004 capital and exploratory expenditures at $8.5 billion, which is about 15 percent higher than spending in 2003. About $6.4 billion, or 75 percent of the total, is targeted for exploration and production activities, with $4.5 billion of that outside the United States. The upstream spending is targeted for the most promising exploratory prospects in Nigeria, Angola and deepwater Gulf of Mexico and major development projects in Kazakhstan, Venezuela and Africa. Included in the upstream expenditures is about $400 million to commercialize the company’s international natural gas resource base, including the construction of additional liquefied natural gas (LNG) facilities to help meet future demand for natural gas. Additional LNG expenditures of about $100 million are included in other segments of the 2004 capital program.

Worldwide downstream spending is estimated to be $1.4 billion, with about $1 billion of the amount on refining and marketing and $400 million on supply and transportation projects. Investments in chemicals are budgeted at $200 million. Estimates for power and related businesses are $150 million. The remaining $300 million is primarily for emerging technologies and information technology infrastructure.

Pension Obligations In 2003, contributions to the U.S. plans totaled $1.2 billion. In early 2004, the company contributed $535 million to the U.S. pension plans. Additionally, the company anticipates contributing about $50 million to the U.S. plans during the remainder of the year. In years subsequent to 2004, the company expects contributions to the U.S. pension plans of about $250 million per year, approximately equal to the cost of benefits earned in each year. In 2003, contributions to the international pension plans were $214 million and contributions of $200 million are anticipated in 2004. The actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations. Refer also to the discussion of pension accounting in “Critical Accounting Estimates and Assumptions” beginning on page FS-18.

FINANCIAL RATIOS

Current Ratio — current assets divided by current liabilities. Generally, two items adversely affected ChevronTexaco’s current ratio, but in the company’s opinion do not affect its liquidity. First, current assets in all



		ChevronTexaco’s ratio of total debt to total debt plus equity fell to 25.8 percent at year-end 2003 as the company’s debt level declined by $3.7 billion.

years included inventories valued on a LIFO basis, which at year-end 2003 were lower than replacement costs, based on average acquisition costs during the year, by approximately $2.1 billion. Second, the company benefits from lower interest rates available on short-term debt by continually refinancing its commercial paper; however, the company’s proportionately large amount of short-term debt in 2002 and 2001 kept its current ratio at relatively low levels.

Interest Coverage Ratio — income before income tax expense, plus interest and debt expense and amortization of capitalized interest, divided by before-tax interest costs. The company’s interest coverage ratio was higher in 2003, primarily due to higher before-tax income, lower average debt balances and lower market interest rates.

Debt Ratio — total debt divided by total debt plus equity. This ratio was approximately 26 percent at December 31, 2003, compared with 34 percent a year earlier.

Financial Ratios


	At December 31
	2003			2002			2001

Current Ratio		1.2			0.9			0.9
Interest Coverage Ratio		24.3			7.6			9.6
Total Debt/Total Debt Plus Equity		25.8	%		34.0	%		33.9	%

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

Direct or Indirect Guarantees*


Millions of dollars	Commitment Expiration by Period
					2005-				After
	Total		2004		2007		2008		2008

Guarantees of Non-Consolidated Affiliates or Joint Venture Obligations	$	917	$	703	$	93	$	6	$	115
Guarantees of Obligations of Third Parties		256		194		36		—		26
Guarantees of Equilon Debt and Leases		238		41		60		18		119

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

At December 31, 2003, the company and its subsidiaries provided guarantees, either directly or indirectly, of $917 million in guarantees for notes and other contractual obligations of affiliated companies and $256 million for third parties as described, by major category, below. There are no amounts being carried as liabilities for the company’s obligations under these guarantees. Of the $917 million in guarantees provided to affiliates, $716 million relate to borrowings for capital projects or general corporate purposes. These guarantees were undertaken to achieve lower interest rates and generally cover the construction period of the capital projects. Approximately 75 percent of the amounts guaranteed will expire in 2004, with the remaining guarantees expiring by the end of 2015. Under the terms of the guarantees, the company would be required to fulfill the guarantee should an affiliate be in default of its loan terms, generally for the full amounts disclosed. There are no recourse provisions, and no assets are held as collateral for these guarantees.

The company provides guarantees of $201 million relating to obligations in connection with pricing of power purchase agreements for certain of its cogeneration affiliates. Under the terms of these guarantees, the company may be required to make payments under certain conditions if the affiliate does not perform under the agreements. There are no recourse provisions to third parties, and no assets are held as collateral for these pricing guarantees.

Guarantees of $256 million have been provided to third parties, including guarantees of approximately $110 million of construction loans to host governments in the company’s international upstream operations. The remaining guarantees of $146 million were provided principally as conditions of sale of the company’s interest in certain operations, to provide a source of liquidity to the guaranteed parties and in connection with company marketing programs. No amounts of the company’s obligations under these guarantees are recorded as liabilities. About 75 percent of the total amounts guaranteed will expire in 2004, with the remainder expiring after 2004. The company would be required to perform under the terms of the guarantees should an entity be in default of its loan or contract terms, generally for the full amounts disclosed. Approximately $100 million of the guarantees have recourse provisions, which enable the company to recover any payments made under the terms of the guarantees from securities held over the guaranteed parties’ assets.

At December 31, 2003, ChevronTexaco had outstanding guarantees for approximately $238 million of Equilon debt and leases. Following the February 2002 disposition of its interest in Equilon, the company received an indemnification from Shell

Oil Company (Shell) for any claims arising from the guarantees. Accordingly, the company has not recorded a liability for these guarantees. Approximately 50 percent of the amounts guaranteed will expire within the 2004–2008 period, with the guarantees of the remaining amounts expiring by 2019.

Indemnifications The company also provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining Inc. in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover certain contingent liabilities, including those associated with the Unocal patent litigation. The company would be required to perform should the indemnified liabilities become actual losses and could be required to make maximum future payments of $300 million. The company has paid approximately $28 million under these contingencies and has disputed approximately $34 million in claims submitted by Shell under these indemnities. Shell has requested arbitration of this dispute, which is expected to occur in mid-2004. There are no recourse provisions enabling recovery of any amounts from third parties nor are any assets held as collateral. Within five years of the February 2002 sale, at the buyer’s option, the company also may be required to purchase certain assets from Shell for their respective net book values, as determined at the time of the company’s purchase. Under these terms, the company purchased two lubricant facilities in late 2003 for immaterial amounts.

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

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

Securitization In other off-balance-sheet arrangements, the company securitizes certain retail and trade accounts receivable in its downstream business through the use of qualifying special purpose entities (SPEs). At December 31, 2003, approximately $1 billion, representing about 11 percent of ChevronTexaco’s total current accounts receivable balance, were securitized. ChevronTexaco’s total estimated financial exposure under these arrangements at December 31, 2003, was approximately $75 million. These arrangements have the effect of accelerating ChevronTexaco’s collection of the securitized amounts. In the event the SPEs experienced major defaults in the collection of receivables, ChevronTexaco believes that it would have no loss exposure connected with third-party investments in these securitization arrangements.

Long-Term Unconditional Purchase Obligations and Commitments, Throughput Agreements, and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, throughput agreements, and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate amounts of required payments under these various commitments are: 2004 – $1.2 billion; 2005 – $1.1 billion; 2006 – $1 billion; 2007 – $1 billion; 2008 – $1 billion; 2009 and after – $1.9 billion. Total payments under the agreements were approximately $1.4 billion in 2003, $1.2 billion in 2002 and $1.5 billion in 2001. The most significant take-or-pay agreement calls for the company to purchase approximately 55,000 barrels per day of refined products from an equity affiliate refiner in Thailand. This purchase agreement is in conjunction with the financing of a refinery owned by the affiliate and expires in 2009. The future estimated commitments under this contract are: 2004 – $700 million; 2005 – $800 million; 2006 – $800 million; 2007 – $800 million; 2008 – $800 million; 2009 – $800 million.

Minority Interests The company has commitments related to preferred shares of subsidiary companies that are accounted for as minority interest. Texaco Capital LLC, a wholly owned finance subsidiary, has issued $65 million of Deferred Preferred Shares Series C. Dividends of approximately $60 million on Series C, at a rate of 7.17 percent compounded annually, will be paid at the redemption date in February 2005 unless earlier redemption occurs. Early redemption may result upon the occurrence of certain specific events. MVP Production Inc., a subsidiary, redeemed variable rate cumulative preferred shares of $75 million owned by one minority holder during 2003.

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

Contractual Obligations


Millions of dollars	Payments Due by Period
					2005–				After
	Total		2004		2007		2008		2008

On Balance Sheet:
Short-Term Debt¹	$	1,703	$	1,703	$	–	$	–	$	–
Long-Term Debt^1,2		10,651		–		5,012		1,044		4,595
Noncancelable Capital Lease Obligations		243		–		64		179		–
Redemption of Subsidiary’s Preferred Shares		160		–		125		–		35
Off Balance Sheet:
Noncancelable Operating Lease Obligations		2,034		299		754		181		800
Unconditional Purchase Obligations		700		300		300		100		–
Through-Put and Take-or-Pay Agreements		6,500		900		2,800		900		1,900

¹ $4,285 of short-term debt that the company expects to refinance is included in long-term debt. The repayment schedule reflects the expiration of the company’s committed credit facilities, although the facilities may be renewed upon expiration.

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

The company also has other obligations connected with asset retirements and pension plans that are not contractually fixed as to timing and amount.

FINANCIAL AND DERIVATIVE INSTRUMENTS

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

The company also uses derivative commodity instruments for trading purposes, the results of which were not material to the company’s financial position, net income or cash flows in 2003.

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

The derivative instruments used in the company’s risk management and trading activities consist mainly of futures contracts traded on the New York Mercantile Exchange and the International Petroleum Exchange; crude oil and natural gas swap contracts; options and other derivative products entered into principally with major financial institutions; and other oil and gas companies. Virtually all derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income. Fair values are derived principally from market quotes and other independent third-party quotes.

The aggregate effect of a 10 percent change in prices for derivative contracts for natural gas, crude oil and petroleum products would be approximately $20 million. The hypothetical effect on these contracts was estimated by calculating the cash value of the contracts as the difference between the hypothetical and contract delivery prices, multiplied by the contract amounts.

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

The aggregate effect on foreign exchange contracts of a hypothetical 10 percent change to year-end exchange rates would be approximately $35 million.

Interest Rates The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements are based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts. Interest rate swaps related to a portion of the company’s fixed-rate debt are accounted for as fair value hedges, whereas interest rate swaps relating to a portion of the company’s floating-rate debt are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. During 2003, no new swaps were initiated. At year-end 2003, the weighted average maturity of “receive fixed” interest rate swaps was approximately five years. There were no “receive floating” swaps outstanding at year end.

A hypothetical 10 percent increase in interest rates upon the interest rate swaps would cause the fair value of the “receive fixed” swaps to decline and the “receive floating” swaps to increase. The aggregate effect of these changes would be approximately $10 million.

TRANSACTIONS WITH RELATED PARTIES

ChevronTexaco enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements. In January 2003, ChevronTexaco and Dynegy agreed to terminate the natural gas sale and purchase agreements. Internationally, there are long-term purchase agreements in place with the company’s refining affiliate in Thailand. Refer to page FS-14 for further discussion. Management believes the foregoing agreements and others have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.

LITIGATION AND OTHER CONTINGENCIES

Unocal Patent Litigation Chevron, Texaco and four other oil companies (refiners) filed suit in 1995, contesting the validity of a patent (‘393’ patent) granted to Unocal Corporation (Unocal) for certain reformulated gasoline blends. ChevronTexaco sells reformulated gasolines in California in certain months of the year. In March 2000, the U.S. Court of Appeals for the Federal Circuit upheld a September 1998 District Court decision that Unocal’s patent was valid and enforceable and assessed damages of 5.75 cents per gallon for gasoline produced during the summer of 1996 that infringed on the claims of the patent. In February 2001, the U.S. Supreme Court concluded it would not review the lower court’s ruling, and the case was sent back to the District Court for an accounting of all infringing gasoline produced after August 1, 1996. The District Court ruled that the

per-gallon damages awarded by the jury are limited to infringement that occurs in California only. Additionally, the U.S. Patent and Trademark Office (USPTO) granted three petitions by the refiners to re-examine the validity of Unocal’s ‘393’ patent and has twice rejected all of the claims in the ‘393’ patent. Those rejections have been appealed by Unocal to the USPTO Board of Appeals. The District Court judge requested further briefing and advised that she would not enter a final judgment in this case until the USPTO had completed its re-examination of the ‘393’ patent. During 2002 and 2003, the USPTO granted two petitions for reexamination of another Unocal patent, the ‘126’ patent. The USPTO has rejected the validity of the claims of the ‘126’ patent, which could affect a larger share of U.S. gasoline production. Separately, in March 2003, the Federal Trade Commission (FTC) filed a complaint against Unocal alleging that its conduct during the pendency of the patents was in violation of antitrust law. In November 2003, the Administrative Law Judge dismissed the complaint brought by the FTC. The FTC has appealed the decision.

Unocal has obtained additional patents that could affect a larger share of U.S. gasoline production. ChevronTexaco believes these additional patents are invalid, unenforceable and/or not infringed. The company’s financial exposure in the event of unfavorable conclusions to the patent litigation and regulatory reviews may include royalties, plus interest, for production of gasoline that is proved to have infringed the patents. The competitive and financial effects on the company’s refining and marketing operations, although presently indeterminable, could be material. ChevronTexaco has been accruing in the normal course of business any future estimated liability for potential infringement of the ‘393’ patent covered by the 1998 trial court’s ruling. In 2000, prior to the merger, Chevron and Texaco made payments to Unocal totaling approximately $30 million for the original court ruling, including interest and fees.

MTBE Another issue involving the company is the petroleum industry’s use of methyl tertiary butyl ether (MTBE) as a gasoline additive and its potential environmental impact through seepage into groundwater. Along with other oil companies, the company is a party to more than 60 lawsuits and claims related to the use of the chemical MTBE in certain oxygenated gasolines. These actions may require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. Chevron-Texaco has reduced the use of MTBE in gasoline it manufactures in the United States, including the complete phase-out of MTBE in California before the end of 2003.



		Reserves for environmental remediation increased 5 percent during 2003. Expenditures during the year were approximately $200 million.

Environmental The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to: Superfund sites and refineries, oil fields, service stations, terminals, and land development areas, whether operating, closed or sold. The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for Superfund sites. In 2003, the company recorded additional provisions for estimated remediation costs, primarily at refined products marketing sites and various closed or divested facilities in the United States.


Millions of dollars	2003			2002			2001

Balance at January 1	$	1,090		$	1,160		$	1,234
Additions		296			229			216
Expenditures		(237	)		(299	)		(290	)

Balance at December 31	$	1,149		$	1,090		$	1,160

As of December 31, 2003, ChevronTexaco had been identified by the Environmental Protection Agency (EPA) or other regulatory agencies under the provisions of the U.S. Superfund law as a potentially responsible party or otherwise involved in the remediation of 218 sites. The company’s remediation reserve for these sites at year-end 2003 was $113 million. The Superfund law provides for joint and several liability for all responsible parties. Any future actions by the EPA and other regulatory agencies to require ChevronTexaco to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s consolidated financial position or liquidity.

It is likely that the company will continue to incur additional liabilities, beyond those recorded, for environmental remediation relating to past operations. These future costs are indeterminable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. Although the amount of future costs may be material to the company’s results of operations in the period in which they are recognized, the company does not expect these costs will have a material adverse effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant

impact on the company’s competitive position relative to other petroleum or chemicals companies.

Prior to January 1, 2003, additional reserves for dismantlement, abandonment and restoration of its worldwide oil, gas and coal properties at the end of their productive lives, which included costs related to environmental issues, were recognized on a unit-of-production basis. Effective January 1, 2003, the company implemented Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). Under FAS 143, the fair value of a liability for an asset retirement obligation is recorded when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. The liability balance for asset retirement obligations at year-end 2003 was $2.9 billion. Refer also to Note 25 on page FS-50 related to FAS 143.

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

Refer to “Environmental Matters” below for additional information related to environmental matters.

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

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

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

businesses and/or to impose additional taxes or royalties on the company’s operations.

In certain locations, host governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries. Internal unrest or strained relations between a host government and the company or other governments may affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries.

Equity Redetermination For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated oil and gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for ChevronTexaco’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills, California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. ChevronTexaco currently estimates its maximum possible net before-tax liability at approximately $200 million. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at about $50 million. The timing of the settlement and the exact amount within this range of estimates is uncertain.

Suspended Wells The company also suspends the costs of exploratory wells pending a final determination of the commercial potential of the related oil and gas fields. The ultimate disposition of these well costs is dependent on the results of future drilling activity and/or development decisions. If the company decides not to continue development, the costs of these wells are expensed. At December 31, 2003, the company had $658 million of suspended exploratory wells included in properties, plant and equipment, an increase of $208 million from 2002 and a decrease of $30 million from 2001. The increase in 2003 primarily reflects drilling activities in the United States and Nigeria.

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

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

ENVIRONMENTAL MATTERS

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

Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In addition to the costs for environmental protection associated with its ongoing operations and products, the company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste-disposal sites used by the company. An obligation may arise when operations are closed or sold and at non-ChevronTexaco sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative and/or remedial work to meet current standards. Using definitions and guidelines established by the American Petroleum Institute, ChevronTexaco estimated its worldwide environmental spending in 2003 at approximately $1.1 billion for its consolidated companies. Included in these expenditures were $305 million of environmental capital expenditures and $820 million of costs associated with the control and abatement of hazardous substances and pollutants from ongoing operations.

For 2004, total worldwide environmental capital expenditures are estimated at $430 million. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.

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

CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS

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

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

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

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

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

For example, the recording of deferred tax assets requires an assessment under the accounting rules that the future realization of the associated tax benefits be “more likely than not.” Another example is the estimation of oil and gas reserves under SEC rules that require “...geological and engineering data (that) demonstrate with reasonable certainty (reserves) to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.” Refer to Table V, “Reserve Quantity Information,” on page FS-57 for the changes in these estimates for the three years ending December 31, 2003, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves,” on page FS-59 for estimates of proved-reserve values for each year-end 2001–2003, which were based on year-end prices at the time. Note 1 to the Consolidated Financial Statements includes a description of the “successful efforts” method of accounting for oil and gas exploration and production activities. The estimates of crude oil and natural gas reserves are important to the timing of expense recognition for costs incurred.

The discussion of the critical accounting policy for “Impairment of Property, Plant and Equipment and Investments in Affiliates” on pages FS-19 and FS-20 includes reference to conditions under which downward revisions of proved reserve quantities could result in impairments of oil and gas properties. This commentary should be read in conjunction with disclosures elsewhere in this discussion and in the Notes to the Consolidated Financial Statements related to estimates, uncertainties, contingencies and new accounting standards. Significant accounting policies are discussed in Note 1 to the Consolidated Financial Statements beginning on page FS-28. The development and selection of accounting estimates and assumptions, including those deemed critical, and the associated disclosures in this discussion have been discussed by management with the audit committee of the Board of Directors.

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

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

Note 21 to the Consolidated Financial Statements, beginning on page FS-42, includes information for the three years ending December 31, 2003, on the components of pension and OPEB expense and the underlying discount rate assumptions as well as on the funded status for the company’s pension plans at the end of 2003 and 2002.

To determine the estimate of long-term rate of return on pension assets, the company employs a rigorous process that incorporates actual historical asset-class returns and an assessment of expected future performance, and takes into consideration external actuarial advice and asset-class risk factors. Asset allocations are regularly updated using pension plan asset/liability studies, and the determination of the company’s estimates of long-term rates of return are consistent with these studies. For example, at December 31, 2003 and 2002, the estimated long-term rate of return on U.S. pension plan assets, which account for about 70 percent of the company’s pension plan assets, was 7.8 percent, as compared with 9 percent at the end of 2001. The year-end market-related value of U.S. pension-plan assets used in the determination of pension expense was based on the market values in the preceding three months as opposed to the maximum allowable period of five years under U.S. accounting rules. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year.

The discount rate used in the determination of pension benefit obligations and pension expense is based on high-quality fixed income investment interest rates. At December 31, 2003, the company calculated the U.S. pension obligations using a 6.0 percent discount rate. The discount rates used at the end of 2002 and 2001 were 6.8 percent and 7.3 percent, respectively.

An increase in the expected return on pension plan assets or the discount rate would reduce pension plan expense, and vice versa. Total pension expense for 2003 was $697 million. As an indication of interest-rate sensitivity to the determination of pension expense, a 1 percent increase in the expected return on assets of the company’s primary U.S. pension plan, which accounted for about 61 percent of the companywide pension obligation, would have reduced total pension plan expense for 2003 by approximately $30 million. A 1 percent increase in the discount rate for this same plan would have reduced total benefit plan expense by approximately $120 million. The actual rates of return on plan assets and discount rates may vary significantly from estimates because of unanticipated changes in the world’s financial markets.

Based on the expected changes in pension plan asset values and pension obligations in 2004, the company does not believe any significant funding of the pension plans will be mandatory during the year. For the U.S. plans, this determination was made in accordance with the minimum funding standard of the Employee Retirement Income Security Act (ERISA). However, the company made discretionary contributions of $535 million to U.S. plans in early 2004. Later in 2004, additional discretionary payments of $200 million and $50 million for the international and U.S. plans, respectively, are anticipated.

Pension expense is included on the Consolidated Statement of Income in “Operating expenses” or “Selling, general and administrative expenses” and applies to all business segments. Depending upon the funding status of the different plans, either a long-term prepaid asset or a long-term liability is recorded for plans with overfunding or underfunding, respectively. Any unfunded accumulated benefit obligation in excess of recorded liabilities is recorded in “Other comprehensive income.” See Note

21 to the Consolidated Financial Statements beginning on page FS-42 for the pension-related balance sheet effects at the end of 2003 and 2002.

For the company’s OPEB plans, expense for 2003 was $228 million and was also recorded as “Operating expenses” or “Selling, general and administrative expenses” in all business segments. The discount rate applied to the company’s U.S. OPEB obligations at December 31, 2003 was 6.0 percent – the same discount rate used for U.S. pension obligations. The assumed health care cost-trend rates used to calculate OPEB obligations starting in 2003 was an 8.4 percent cost increase over the previous year gradually dropping over four years to a long-term ultimate rate-increase assumption of 4.5 percent for 2007 and thereafter. The health care cost-trend increase assumption and duration to reach that rate are company estimates, developed in consultation with external consultants, and are consistent with the company’s actual experience.

As an indication of discount-rate sensitivity to the determination of OPEB expense in 2003, a 1 percent increase in the discount rate for the company’s primary U.S. OPEB plan, which accounted for the significant majority of the companywide OPEB obligation, would have decreased OPEB expense by approximately $10 million.

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

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

The amount and income statement classification of major impairments of PP&E for the three years ending December 31, 2003, are included in the commentary on the business segments elsewhere in this discussion, as well as in Note 3 to the Consolidated Financial Statements on pages FS-30 and FS-31. An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in the impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

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

income statement for the difference between the investment’s carrying value and its estimated fair value at the time. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. Differing assumptions could affect whether an investment is impaired in any period and the amount of the impairment and are not subject to sensitivity analysis.

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

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

Under the accounting rules, a liability is recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally records these losses as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income. Refer to the business segment discussions elsewhere in this discussion and in Note 3 to the Consolidated Financial Statements on pages FS-30 and FS-31 for the effect on earnings from losses associated with certain litigation and environmental remediation and tax matters for the three years ended December 31, 2003.

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

NEW ACCOUNTING STANDARDS

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, "Consolidation of Variable Interest Entities” (FIN 46). FIN 46 amended Accounting Research Bulletin (ARB) 51, “Consolidated Financial Statements,” and established standards for determining circumstances under which a variable interest entity (VIE) should be consolidated by its primary beneficiary. FIN 46 also requires disclosures about VIEs that the company is not required to consolidate but in which it has a significant variable interest. In December 2003, the FASB issued FIN 46-R, which not only included amendments to FIN 46, but also required application of the interpretation to all affected entities no later than March 31, 2004 for calendar-year reporting companies. Prior to this requirement, however, companies must apply the interpretation to special-purpose entities by December 31, 2003. The adoption of FIN 46-R as it relates to special-purpose entities did not have a material impact on the company’s results of operations, financial position or liquidity, and the company does not expect a material impact upon its full adoption of the interpretation as of March 31, 2004.

ACCOUNTING FOR MINERAL INTERESTS INVESTMENT

The SEC has questioned certain public companies in the oil and gas and mining industries as to the proper accounting for, and reporting of, acquired contractual mineral interests under FASB Statement No. 141, “Business Combinations” (FAS 141), and FASB Statement No. 142, “Goodwill and Intangible Assets” (FAS 142). These accounting standards became effective for the company on July 1, 2001, and January 1, 2002, respectively.

At issue is whether such mineral interest costs should be classified on the balance sheet as part of “Properties, plant and equipment” or as “Intangible assets.” The company will continue to classify these costs as “Properties, plant and equipment” and apportion them to expense in future periods under the company’s existing accounting policy until authoritative guidance is provided.

For ChevronTexaco, the net book values of this category of mineral interest investment at December 31, 2003 and 2002, were $3.8 billion and $4.1 billion, respectively. If reclassification of these balances becomes necessary, the company’s statements of income and cash flows would not be affected. However, additional disclosures related to intangible assets would be required as prescribed under the associated accounting standards.

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) on page 30 present fairly, in all material respects, the financial position of ChevronTexaco Corporation and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a) (2) on page 30 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
San Francisco, California
February 25, 2004


	Year ended December 31
	2003			2002			2001

REVENUES AND OTHER INCOME
Sales and other operating revenues*	$	120,032		$	98,691		$	104,409
Income (loss) from equity affiliates		1,029			(25	)		1,144
Gain from exchange of Dynegy preferred stock		365			–			–
Other income		335			247			692

TOTAL REVENUES AND OTHER INCOME		121,761			98,913			106,245

COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products		71,583			57,249			60,549
Operating expenses		8,553			7,848			7,650
Selling, general and administrative expenses		4,440			4,155			3,984
Exploration expenses		571			591			1,039
Depreciation, depletion and amortization		5,384			5,231			7,059
Write-down of investments in Dynegy Inc.		–			1,796			–
Merger-related expenses		–			576			1,563
Taxes other than on income*		17,906			16,689			15,156
Interest and debt expense		474			565			833
Minority interests		80			57			121

TOTAL COSTS AND OTHER DEDUCTIONS		108,991			94,757			97,954

INCOME BEFORE INCOME TAX EXPENSE		12,770			4,156			8,291
INCOME TAX EXPENSE		5,344			3,024			4,360

NET INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES	$	7,426		$	1,132		$	3,931
Extraordinary loss, net of tax		–			–			(643	)
Cumulative effect of changes in accounting principles		(196	)		–			–

NET INCOME	$	7,230		$	1,132		$	3,288

PER-SHARE AMOUNTS
BASIC:
NET INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES	$	7.15		$	1.07		$	3.71
Extraordinary item	$	–		$	–		$	(0.61	)
Cumulative effect of changes in accounting principles	$	(0.18	)	$	–		$	–
NET INCOME	$	6.97		$	1.07		$	3.10
DILUTED:
NET INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES	$	7.14		$	1.07		$	3.70
Extraordinary item	$	–		$	–		$	(0.61	)
Cumulative effect of changes in accounting principles	$	(0.18	)	$	–		$	–
NET INCOME	$	6.96		$	1.07		$	3.09

*Includes consumer excise taxes:	$	7,095		$	7,006		$	6,546


	Year ended December 31
	2003			2002			2001

NET INCOME	$	7,230		$	1,132		$	3,288

Currency translation adjustment
Unrealized net change arising during period		32			15			(11	)

Unrealized holding gain on securities
Net gain (loss) arising during period
Before income taxes		445			(149	)		3
Income taxes		–			52			–
Reclassification to net income of net realized (gain) loss
Before income taxes		(365	)		217			–
Income taxes		–			(76	)		–

Total		80			44			3

Net derivatives gain on hedge transactions
Before income taxes		115			52			3
Income taxes		(40	)		(18	)		–

Total		75			34			3

Minimum pension liability adjustment
Before income taxes		12			(1,208	)		14
Income taxes		(10	)		423			(5	)

Total		2			(785	)		9

OTHER COMPREHENSIVE GAIN (LOSS), NET OF TAX		189			(692	)		4

COMPREHENSIVE INCOME	$	7,419		$	440		$	3,292


	At December 31
	2003			2002

ASSETS
Cash and cash equivalents	$	4,266		$	2,957
Marketable securities		1,001			824
Accounts and notes receivable (less allowance: 2003 – $179; 2002 – $181)		9,722			9,385
Inventories:
Crude oil and petroleum products		2,003			2,019
Chemicals		173			193
Materials, supplies and other		472			551

		2,648			2,763
Prepaid expenses and other current assets		1,789			1,847

TOTAL CURRENT ASSETS		19,426			17,776
Long-term receivables, net		1,493			1,338
Investments and advances		12,319			11,097
Properties, plant and equipment, at cost		100,556			105,231
Less: Accumulated depreciation, depletion and amortization		56,018			61,076

		44,538			44,155
Deferred charges and other assets		2,594			2,993
Assets held for sale		1,100			–

TOTAL ASSETS	$	81,470		$	77,359

LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt	$	1,703		$	5,358
Accounts payable		8,675			8,455
Accrued liabilities		3,172			3,364
Federal and other taxes on income		1,392			1,626
Other taxes payable		1,169			1,073

TOTAL CURRENT LIABILITIES		16,111			19,876
Long-term debt		10,651			10,666
Capital lease obligations		243			245
Deferred credits and other noncurrent obligations		7,758			4,474
Noncurrent deferred income taxes		6,417			5,619
Reserves for employee benefit plans		3,727			4,572
Minority interests		268			303

TOTAL LIABILITIES		45,175			45,755

Preferred stock (authorized 100,000,000 shares, $1.00 par value; none issued)		–			–
Common stock (authorized 4,000,000,000 shares, $0.75 par value; 1,137,021,057 shares issued)		853			853
Capital in excess of par value		4,855			4,833
Retained earnings		35,315			30,942
Accumulated other comprehensive loss		(809	)		(998	)
Deferred compensation and benefit plan trust		(602	)		(652	)
Treasury stock, at cost (2003 – 67,873,337 shares; 2002 – 68,884,416 shares)		(3,317	)		(3,374	)

TOTAL STOCKHOLDERS’ EQUITY		36,295			31,604

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	81,470		$	77,359


	Year ended December 31
	2003			2002			2001

OPERATING ACTIVITIES
Net income	$	7,230		$	1,132		$	3,288
Adjustments
Cumulative effect of changes in accounting principles		196			–			–
Depreciation, depletion and amortization		5,384			5,231			7,059
Write-down of investments in Dynegy, before tax		–			1,796			–
Dry hole expense		256			288			646
Distributions (less) more than income from equity affiliates		(383	)		510			(489	)
Net before-tax gains on asset retirements and sales		(194	)		(33	)		(116	)
Gain from exchange of Dynegy preferred stock		(365	)		–			–
Net foreign currency losses (gains)		199			5			(122	)
Deferred income tax provision		164			(81	)		(768	)
Net decrease in operating working capital		162			1,125			643
Extraordinary before-tax loss on merger-related asset dispositions		–			–			787
Minority interest in net income		80			57			121
Decrease (increase) in long-term receivables		12			(39	)		(9	)
Decrease in other deferred charges		1,646			428			61
Cash contributions to employee pension plans		(1,417	)		(246	)		(107	)
Other		(655	)		(230	)		481

NET CASH PROVIDED BY OPERATING ACTIVITIES		12,315			9,943			11,475

INVESTING ACTIVITIES
Capital expenditures		(5,625	)		(7,597	)		(9,713	)
Proceeds from asset sales		1,107			2,341			298
Proceeds from redemption of Dynegy securities		225			–			–
Net sales (purchases) of marketable securities		153			209			(183	)
Net sales of other short-term investments		–			–			56
Repayment of loans by equity affiliates		68			–			–

NET CASH USED FOR INVESTING ACTIVITIES		(4,072	)		(5,047	)	$	(9,542	)

FINANCING ACTIVITIES
Net (payments) borrowings of short-term obligations		(3,628	)		(1,810	)		3,830
Proceeds from issuances of long-term debt		1,034			2,045			412
Repayments of long-term debt and other financing obligations		(1,347	)		(1,356	)		(2,856	)
Redemption of Market Auction Preferred Shares		–			–			(300	)
Redemption of preferred stock by subsidiaries		(75	)		–			(463	)
Issuance of preferred stock by subsidiaries		–			–			12
Cash dividends
Common stock		(3,033	)		(2,965	)		(2,733	)
Preferred stock		–			–			(6	)
Dividends paid to minority interests		(37	)		(26	)		(119	)
Net sales of treasury shares		57			41			110

NET CASH USED FOR FINANCING ACTIVITIES		(7,029	)		(4,071	)		(2,113	)

EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS		95			15			(31	)

NET CHANGE IN CASH AND CASH EQUIVALENTS		1,309			840			(211	)
CASH AND CASH EQUIVALENTS AT JANUARY 1		2,957			2,117			2,328

CASH AND CASH EQUIVALENTS AT DECEMBER 31	$	4,266		$	2,957		$	2,117


			2003					2002						2001

	Shares		Amount			Shares		Amount			Shares			Amount

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

BALANCE AT DECEMBER 31		–	$	–			–	$	–			–		$	–

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

BALANCE AT DECEMBER 31		1,137,021	$	853			1,137,021	$	853			1,137,021		$	853

CAPITAL IN EXCESS OF PAR
Balance at January 1			$	4,833				$	4,811					$	5,505
Retirement of Texaco treasury stock				–					–						(739	)
Change in common stock par value				–					–						–
Treasury stock transactions				22					22						45

BALANCE AT DECEMBER 31			$	4,855				$	4,833					$	4,811

RETAINED EARNINGS
Balance at January 1			$	30,942				$	32,767					$	32,206
Net income				7,230					1,132						3,288
Cash dividends
Common stock				(3,033	)				(2,965	)					(2,733	)
Preferred stock
Market Auction Preferred Shares				–					–						(6	)
Tax benefit from dividends paid on unallocated ESOP shares and other				6					8						12
Exchange of Dynegy securities				170					–						–

BALANCE AT DECEMBER 31			$	35,315				$	30,942					$	32,767


				2003						2002						2001

	Shares			Amount			Shares			Amount			Shares			Amount

ACCUMULATED OTHER COMPREHENSIVE LOSS
Currency translation adjustment
Balance at January 1				$	(208	)				$	(223	)				$	(212	)
Change during year					32						15						(11	)

Balance at December 31				$	(176	)				$	(208	)				$	(223	)
Minimum pension liability adjustment
Balance at January 1				$	(876	)				$	(91	)				$	(100	)
Change during year					2						(785	)					9

Balance at December 31				$	(874	)				$	(876	)				$	(91	)
Unrealized net holding gain on securities
Balance at January 1				$	49					$	5					$	2
Change during year					80						44						3

Balance at December 31				$	129					$	49					$	5
Net derivatives gain on hedge transactions
Balance at January 1				$	37					$	3					$	–
Change during year					75						34						3

Balance at December 31				$	112					$	37					$	3

BALANCE AT DECEMBER 31				$	(809	)				$	(998	)				$	(306	)

DEFERRED COMPENSATION AND BENEFIT PLAN TRUST
DEFERRED COMPENSATION
Balance at January 1				$	(412	)				$	(512	)				$	(681	)
Net reduction of ESOP debt and other					50						100						106
Restricted stock
Awards					–						–						(35	)
Amortization and other					–						–						12
Vesting upon merger					–						–						86

BALANCE AT DECEMBER 31					(362	)					(412	)					(512	)
BENEFIT PLAN TRUST (COMMON STOCK)		7,084			(240	)		7,084			(240	)		7,084			(240	)

BALANCE AT DECEMBER 31		7,084		$	(602	)		7,084		$	(652	)		7,084		$	(752	)

TREASURY STOCK AT COST
Balance at January 1		68,884		$	(3,374	)		69,800		$	(3,415	)		84,835		$	(4,273	)
Purchases		40			(3	)		38			(3	)		141			(9	)
Retirement of Texaco treasury stock		–			–			–			–			(12,500	)		748
Issuances – mainly employee benefit plans		(1,051	)		60			(954	)		44			(2,676	)		119

BALANCE AT DECEMBER 31		67,873		$	(3,317	)		68,884		$	(3,374	)		69,800		$	(3,415	)

TOTAL STOCKHOLDERS’ EQUITY AT DECEMBER 31				$	36,295					$	31,604					$	33,958

NOTE 1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

In preparing its Consolidated Financial Statements, the company follows accounting principles generally accepted in the United States of America. This requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. While the company uses its best estimates and judgments, actual results could differ from these estimates as future confirming events occur.

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

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

Investments are assessed for possible impairment when there are indications that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in the common stock of these equity investees is not changed for subsequent recov-

eries in fair value. Subsequent recoveries in the carrying value of other investments are reported in “Other comprehensive income.”

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

Derivatives The majority of the company’s activity in commodity derivative instruments is intended to manage the price risk posed by physical transactions. For some of this derivative activity, generally limited to large, discrete or infrequently occurring transactions, the company may elect to apply fair value or cash flow hedge accounting. For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company has elected not to apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s trading activity, gains and losses from the derivative instruments are reported in current income. For derivative instruments relating to foreign currency exposures, gains and losses are reported in current income. Interest rate swaps — hedging a portion of the company’s fixed-rate debt — are accounted for as fair value hedges, whereas interest rate swaps relating to a portion of the company’s floating-rate debt are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income.

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

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

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

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

mination as to whether proved reserves were found cannot be made within one year following completion of drilling. All other exploratory wells and costs are expensed.

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

Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value with the fair value less the cost to sell. If the net book value exceeds the sales value, the asset is considered impaired resulting in an adjustment to the lower value.

Effective January 1, 2003, the company implemented Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143), in which the fair value of a liability for an asset retirement obligation is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. See also Note 25 on page FS-50 relating to asset retirement obligations, which includes additional information on the company’s adoption of FAS 143. Previously, for oil, gas and coal producing properties, a provision was made through depreciation expense for anticipated abandonment and restoration costs at the end of the property’s useful life.

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

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

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

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

Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Liabilities related to future remediation costs are recorded when environmental assessments and/or cleanups are probable and the costs can be reasonably estimated. For the company’s U.S. and Canadian marketing facilities, the accrual is based in part on the probability that a future remediation commitment will be required. For oil, gas and coal producing properties, a liability for an asset retirement obligation is made following FAS 143, which the company implemented effective January 1, 2003. See Note 25 on page FS-50 related to FAS 143.

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

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

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

Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products, and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which ChevronTexaco has an interest with other producers are generally recognized on the basis of the company’s net working interest (entitlement method).

Stock Compensation At December 31, 2003, the company had stock-based employee compensation plans, which are described more fully in Note 22 beginning on page FS-46. The company accounts for those plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The following table illustrates the effect on net income and earnings per share if the company had applied the fair-value-recognition provisions of Financial Accounting Standards Board (FASB) Statement No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation:


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

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued


	Year ended December 31
	2003			2002			2001

Net income, as reported	$	7,230		$	1,132		$	3,288
Add: Stock-based employee compensation expense included in reported net income determined under APB No. 25, net of related tax effects		1			(1	)		68
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects		(26	)		(48	)		(154	)

Pro forma net income	$	7,205		$	1,083		$	3,202

Earnings per share:*
Basic – as reported	$	6.97		$	1.07		$	3.10
Basic – pro forma	$	6.94		$	1.02		$	3.02
Diluted – as reported	$	6.96		$	1.07		$	3.09
Diluted – pro forma	$	6.93		$	1.02		$	3.01

The amounts in 2003 include a benefit of $0.16 for the company’s share of a capital stock transaction of its Dynegy Inc. affiliate, which under the applicable accounting rules was recorded directly to the company’s retained earnings and not included in net income for the period.

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

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

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

NOTE 2.

TEXACO MERGER TRANSACTION AND EXTRAORDINARY ITEM

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


	Nine months ended
	September 30
	2001

Revenues and other income
Chevron	$	37,213
Texaco¹		39,469
Adjustments/eliminations²		8,103

ChevronTexaco	$	84,785

Net income
Chevron	$	4,092
Texaco¹		2,214

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

ChevronTexaco	$	5,810

¹		Includes certain reclassification adjustments to conform to historical Chevron presentation.
²		Consolidation of former equity operations and intercompany eliminations.
³		Loss associated with the sales of the company’s interests in Equilon and Motiva.

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

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

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

Net income for 2001 included a loss of $643, net of a tax benefit of $144 ($0.61 per common share – diluted), related to the disposition of assets that were required as a condition of the FTC approval of the merger and other assets that were made duplicative by the merger. All such assets sold as a result of the merger provided net income of approximately $375 in 2001. The after-tax loss on these dispositions was reported as an extraordinary item in accordance with pooling-of-interests accounting requirements.

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

NOTE 3.

SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION

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

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

NOTE 3. SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION – Continued


		Year ended December 31
		2003			2002			2001

Special Items
Asset write-offs and revaluations
Exploration and Production
Impairments	- United States	$	(103	)	$	(183	)	$	(1,168	)
	- International		(30	)		(100	)		(247	)
Refining, Marketing and Transportation
Impairments	- United States		–			(66	)		–
	- International		(123	)		(136	)		(46	)
Chemicals
Manufacturing facility
Impairment	- United States		–			–			(32	)
Other asset write-offs			–			–			(64	)
All Other
Other asset write-offs			(84	)		–			(152	)

			(340	)		(485	)		(1,709	)

Asset dispositions
Exploration and Production
United States			77			–			49
International			32			–			–
Refining, Marketing and Transportation
United States			37			–			–
International			(24	)		–			–

			122			–			49

Tax adjustments			118			60			(5	)

Environmental remediation provisions			(132	)		(160	)		(78	)

Restructuring and reorganizations			(146	)		–			–
Merger-related expenses			–			(386	)		(1,136	)
Extraordinary loss on merger-related asset sales			–			–			(643	)
Litigation and provisions			–			(57	)		–

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

			325			(2,306	)		–

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

In 2003, the company recorded impairments of $103 and $30, respectively, for various U.S. and international oil and gas producing properties, reflecting lower expected recovery of proved reserves or a write-down to market value for assets in anticipation of sale. Impairments of $123 on downstream assets were for the conversion of a refinery to a products terminal and a write-down to market value for assets in anticipation of sale. Also in 2003, ChevronTexaco exchanged its Dynegy Series B Preferred Stock for cash, notes and Series C Preferred Stock. The $365 difference between the fair value of these items and the company’s carrying value was included in net income.

In 2002, the company recorded write-downs of $1,626 of its investment in Dynegy common and preferred stock and $136 of its investment in its publicly traded Caltex Australia affiliate to their respective estimated fair values. The write-downs were required because the declines in the fair values of the investments below their carrying values were deemed to be other than temporary. Refer to Note 14 on pages FS-38 and FS-39 for additional information on the company’s investment in Dynegy and Caltex Australia.

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

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


	Year ended December 31
	2003			2002			2001

Revenues and other income
Income (loss) from equity affiliates	$	179		$	(829	)	$	(123	)
Other income		217			–			84

Total revenues and other income		396			(829	)		(39	)

Costs and other deductions
Operating expenses		329			259			25
Selling, general and administrative expenses		146			180			139
Depreciation, depletion and amortization		286			298			2,294
Merger-related expenses		–			576			1,563
Taxes other than on income		–			–			12
Write-down of investments in Dynegy Inc.		–			1,796			–

Total costs and other deductions		761			3,109			4,033

Income before income tax expense		(365	)		(3,938	)		(4,072	)
Income tax benefit		(312	)		(604	)		(1,193	)

Net income before extraordinary item	$	(53	)	$	(3,334	)	$	(2,879	)
Extraordinary loss, net of income tax		–			–			(643	)

Net income	$	(53	)	$	(3,334	)	$	(3,522	)

Other financial information is as follows:


	Year ended December 31
	2003			2002			2001

Total financing interest and debt costs	$	549		$	632		$	955
Less: Capitalized interest		75			67			122

Interest and debt expense	$	474		$	565		$	833

Research and development expenses	$	238		$	221		$	209
Foreign currency (losses) gains*	$	(404	)	$	(43	)	$	191

Includes $(96), $(66) and $12 in 2003, 2002 and 2001, respectively, for the company’s share of equity affiliates’ foreign currency (losses) gains.

The excess of market value over the carrying value of inventories for which the LIFO method is used was $2,106, $1,571 and $1,580 at December 31, 2003, 2002 and 2001, respectively. Market value is generally based on average acquisition costs for the year. LIFO profits of $82, $13 and $10 were included in net income for the years 2003, 2002 and 2001, respectively.


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

NOTE 4.

INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS

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


	Year ended December 31
	2003			2002			2001

(Increase) decrease in accounts and notes receivable	$	(265	)	$	(1,135	)	$	2,472
Decrease (increase) in inventories		115			185			(294	)
Decrease (increase) in prepaid expenses and other current assets		261			92			(211	)
Increase (decrease) in accounts payable and accrued liabilities		242			1,845			(742	)
(Decrease) increase in income and other taxes payable		(191	)		138			(582	)

Net decrease in operating working capital	$	162		$	1,125		$	643

Net cash provided by operating activities includes the following cash payments for interest and income taxes:
Interest paid on debt (net of capitalized interest)	$	467		$	533		$	873
Income taxes paid	$	5,316		$	2,916		$	5,465

Net (purchases) sales of marketable securities consist of the following gross amounts:
Marketable securities purchased	$	(3,563	)	$	(5,789	)	$	(2,848	)
Marketable securities sold		3,716			5,998			2,665

Net sales (purchases) of marketable securities	$	153		$	209		$	(183	)

The 2003 “Net Cash Provided by Operating Activities” includes an $890 “Decrease in other deferred charges” and a decrease of the same amount in “Other” related to balance sheet reclassifications for certain pension-related assets and liabilities, in accordance with the requirements of FAS 87, “Employers’ Accounting for Pensions.”

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


	Year ended December 31
	2003			2002			2001

Additions to properties, plant and equipment¹	$	4,953		$	6,262		$	6,445
Additions to investments		687			1,138			2,902	²
Current-year dry-hole expenditures		132			252			418
Payments for other liabilities and assets, net		(147	)		(55	)		(52	)

Capital expenditures		5,625			7,597			9,713
Expensed exploration expenditures		315			303			393
Payments of long-term debt and other financing obligations, net		286	³		2			210	³

Capital and exploratory expenditures, excluding equity affiliates		6,226			7,902			10,316
Equity in affiliates’ expenditures		1,137			1,353			1,712

Capital and exploratory expenditures, including equity affiliates	$	7,363		$	9,255		$	12,028

¹		Net of noncash items of $1,183 in 2003, $195 in 2002 and $63 in 2001.
²		Includes $1,500 for investment in Dynegy preferred stock.
³		Deferred payments of $210 related to 1993 acquisition of an interest in the Tengizchevroil joint venture were made in 2003 and 2001.

NOTE 5.

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

Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron-Texaco Corporation. CUSA and its subsidiaries manage and operate most of ChevronTexaco’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas and natural gas liquids and those associated with the refining, marketing, supply and distribution of products derived from petroleum, other than natural gas liquids, excluding most of the regulated pipeline operations of ChevronTexaco. CUSA also holds ChevronTexaco’s investments in the CPChem joint venture and Dynegy, which are accounted for using the equity method.

During 2002 and 2003, ChevronTexaco implemented legal reorganizations in which certain ChevronTexaco subsidiaries transferred assets to or under CUSA and other ChevronTexaco companies were merged with and into CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the table below gives retroactive effect to the reorganization in a manner similar to a pooling of interests, with all periods presented as if the companies had always been combined and the reorganization had occurred on January 1, 2001. However, the financial information included below may not reflect the financial position and operating results in the future or the historical results in the periods presented had the reorganization actually occurred on January 1, 2001.


	Year ended December 31
	2003		2002			2001

Sales and other operating revenues	$	82,845	$	66,910		$	57,576
Total costs and other deductions		78,448		68,579			56,371
Net income (loss)*		3,083		(1,895	)		1,268

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


	At December 31
	2003		2002

Current assets	$	15,539	$	13,244
Other assets		21,348		24,563
Current liabilities		13,122		19,170
Other liabilities		14,136		12,977
Net equity		9,629		5,660

Memo: Total debt	$	9,091	$	8,137

NOTE 5. SUMMARIZED FINANCIAL DATA — CHEVRON U.S.A. INC. — Continued

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

NOTE 6.

SUMMARIZED FINANCIAL DATA — CHEVRON TRANSPORT CORPORATION LTD.

Chevron Transport Corporation Ltd. (CTC), incorporated in Bermuda, is an indirect, wholly owned subsidiary of ChevronTexaco Corporation. CTC is the principal operator of ChevronTexaco’s international tanker fleet and is engaged in the marine transportation of crude oil and refined petroleum products. Most of CTC’s shipping revenue is derived from providing transportation services to other ChevronTexaco companies. ChevronTexaco Corporation has guaranteed this subsidiary’s obligations in connection with certain debt securities issued by a third party. Summarized financial information for CTC and its consolidated subsidiaries is presented as follows:


	Year ended December 31
	2003		2002			2001

Sales and other operating revenues	$	601	$	850		$	859
Total costs and other deductions		535		922			793
Net income (loss)		50		(79	)		67


	At December 31
	2003		2002

Current assets	$	116	$	273
Other assets		338		464
Current liabilities		96		334
Other liabilities		243		344
Net equity		115		59

During 2003, CTC’s paid-in capital increased by $6 from additional capital contributions and settlements.

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at December 31, 2003.

NOTE 7.

STOCKHOLDERS’ EQUITY

Retained earnings at December 31, 2003 and 2002, included approximately $1,300 and $1,600, respectively, for the company’s share of undistributed earnings of equity affiliates.

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

In 1998, in connection with the renewal of Chevron’s Stockholder Rights Plan, Chevron declared a dividend distribution on each outstanding share of its common stock of one Right to purchase participating preferred stock. The Rights issued under the plan became exercisable, unless redeemed earlier by ChevronTexaco, if a person or group commenced a tender or exchange offer or acquired or obtained the right to acquire 10 percent or more of the outstanding shares of common stock without the prior consent of ChevronTexaco. In October 2002, the

Stockholder Rights agreement was amended so that the Rights would expire in November 2003, five years earlier than the initial expiration date in November 2008. No event made the Rights exercisable prior to their expiration in November 2003.

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

At December 31, 2003, 30 million shares of ChevronTexaco’s authorized but unissued common stock were reserved for issuance under the ChevronTexaco Corporation Long-Term Incentive Plan (LTIP), which was approved by the stockholders in 1990. Through the end of 2003, all of the plan’s common stock requirements were met from the company’s treasury stock, and there had been no issuances of reserved shares.

NOTE 8.

FINANCIAL AND DERIVATIVE INSTRUMENTS

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

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

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

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

The fair values of the outstanding contracts are reported on the Consolidated Balance Sheet as “Accounts and notes receivable,” “Accounts payable,” “Long-term receivables — net,” and “Deferred credits and other noncurrent obligations.” Gains and losses on the company’s risk management activities are reported as either “Sales and other operating revenues” or “Purchased crude oil and products,” whereas trading gains and losses are reported as “Other income.” These activities are reported under “Operating activities” in the Consolidated Statement of Cash Flows.


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

NOTE 8. FINANCIAL AND DERIVATIVE INSTRUMENTS — Continued

The fair values of the outstanding contracts are reported on the Consolidated Balance Sheet as “Accounts and notes receivable” or “Accounts payable,” with gains and losses reported as “Other income.” These activities are reported under “Operating activities” in the Consolidated Statement of Cash Flows.

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

During 2003, no new swaps were initiated. At year-end 2003, the interest rate swaps outstanding related to fixed-rate debt, and their weighted average maturity was approximately 4.6 years.

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

Fair Value Fair values are derived either from quoted market prices or, if not available, the present value of the expected cash flows. The fair values reflect the cash that would have been received or paid if the instruments were settled at year-end.

Long-term debt of $7,229 and $7,296 had estimated fair values of $7,709 and $7,971 at December 31, 2003 and 2002, respectively.

For interest rate swaps, the notional principal amounts of $665 and $665 had estimated fair values of $65 and $70 at December 31, 2003 and 2002, respectively.

The company holds cash equivalents and U.S. dollar marketable securities in domestic and offshore portfolios. Eurodollar bonds, floating-rate notes, time deposits and commercial paper are the primary instruments held. Cash equivalents and marketable securities had fair values of $3,803 and $2,506 at December 31, 2003 and 2002, respectively. Of these balances, $2,803 and $1,682 at the respective year-ends were classified as cash equivalents that had average maturities under 90 days. The remainder, classified as marketable securities, had average maturities of approximately 3.5 years.

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

The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s broad customer base worldwide. As a consequence, concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered sufficient, Letters of Credit are the principal security obtained to support lines of credit.

Investment in Dynegy Notes and Preferred Stock At the beginning of 2003, the company held $1,500 aggregate principal amount of Dynegy Series B Preferred Stock, which was due for redemption at par value in November 2003. In August, the company exchanged its preferred stock for $225 in cash, $225 face value of Dynegy Junior Unsecured Subordinated Notes due 2016 and $400 face value of Dynegy Series C Convertible Preferred Stock with a stated maturity of 2033.

The company recorded the Junior Notes and Series C Preferred Stock on the date of exchange at their fair values of $170 and $270, respectively, for a total of $440. Together with the $225 cash, the total amount recorded on the date of exchange was $665. A gain of $365 was included in net of income at that date for the difference between the $665 fair value received and the net balance sheet amount of $300 associated with the Series B shares.

At December 31, 2003, the estimated fair values of the Junior Notes and Series C shares totaled $530. The $90 difference from the $440 recorded in August was recorded to “Investments and advances,” with an offsetting amount in “Other comprehensive income.” Future temporary changes in the estimated fair values of the new securities likewise will be reported in “Other comprehensive income.” However, if any future decline in fair value is deemed to be other than temporary, a charge against income in the period would be recorded. Interest that accrues on the notes and dividends payable on the preferred stock is recognized in income each period.

NOTE 9.

OPERATING SEGMENTS AND GEOGRAPHIC DATA

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

Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Non-billable costs and merger-related items remain at the corporate level. Included in net income for 2003 were net charges of $196 for the cumulative effect of accounting principle changes, primarily relating to a new accounting standard for recognizing asset retirement obligations. The net amount was composed of

NOTE 9. OPERATING SEGMENTS AND GEOGRAPHIC DATA – Continued

$350 of charges for U.S. Exploration and Production and credits of $145 and $9 for International Exploration and Production and All Other, respectively. After-tax segment income (loss) is presented in the following table:


	Year ended December 31
	2003			2002			2001

Exploration and Production
United States	$	2,833		$	1,717		$	1,779
International		3,365			2,839			2,533

Total Exploration and Production		6,198			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
United States		5			13			(186	)
International		64			73			58

Total Chemicals		69			86			(128	)

Total Segment Income		7,434			4,275			5,998
Merger-related expenses		–			(386	)		(1,136	)
Extraordinary loss		–			–			(643	)
Interest expense		(352	)		(406	)		(552	)
Interest income		75			72			147
Other		73			(2,423	)		(526	)

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

Segment Assets Segment assets do not include intercompany investments or intercompany receivables. Segment assets at year-end 2003 and 2002 follow:


	At December 31
	2003		2002

Exploration and Production
United States	$	12,501	$	11,671
International		28,520		26,172

Total Exploration and Production		41,021		37,843

Refining, Marketing and Transportation
United States		9,354		9,681
International		17,627		17,699

Total Refining, Marketing and Transportation		26,981		27,380

Chemicals
United States		2,165		2,154
International		662		698

Total Chemicals		2,827		2,852

Total Segment Assets		70,829		68,075

All Other
United States		6,644		5,364
International		3,997		3,920

Total All Other		10,641		9,284

Total Assets – United States		30,664		28,870
Total Assets – International		50,806		48,489

Total Assets	$	81,470	$	77,359

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2003, 2002 and 2001 are presented in the following table. Sales from the transfer of products between segments are at prices that approximate market prices.

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

Other than the United States, the only country where Chevron-Texaco generates significant revenues is the United Kingdom, where revenues amounted to $12,121, $10,816 and $10,350 in 2003, 2002 and 2001, respectively.


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

NOTE 9. OPERATING SEGMENTS AND GEOGRAPHIC DATA – Continued


	Year ended December 31
	2003			2002			2001

Exploration and Production
United States	$	6,928		$	4,998		$	12,744
Intersegment		6,295			4,217			2,923

Total United States		13,223			9,215			15,667

International		7,384			5,637			9,127
Intersegment		8,142			8,377			7,376

Total International		15,526			14,014			16,503

Total Exploration and Production		28,749			23,229			32,170

Refining, Marketing and Transportation
United States		44,701			33,880			29,294
Excise taxes		3,744			3,990			3,954
Intersegment		219			163			392

Total United States		48,664			38,033			33,640

International		52,486			45,759			45,248
Excise taxes		3,342			3,006			2,580
Intersegment		–			43			452

Total International		55,828			48,808			48,280

Total Refining, Marketing and Transportation		104,492			86,841			81,920

Chemicals
United States		323			323			335
Intersegment		129			109			89

Total United States		452			432			424

International		677			638			670
Excise taxes		9			10			12
Intersegment		83			68			65

Total International		769			716			747

Total Chemicals		1,221			1,148			1,171

All Other
United States		338			413			408
Intersegment		121			105			60

Total United States		459			518			468

International		100			37			37
Intersegment		4			–			9

Total International		104			37			46

Total All Other		563			555			514

Segment Sales and Other
Operating revenues
United States		62,798			48,198			50,199
International		72,227			63,575			65,576

Total Segment Sales and Other
Operating revenues		135,025			111,773			115,775
Elimination of intersegment sales		(14,993	)		(13,082	)		(11,366	)

Total Sales and Other Operating Revenues	$	120,032		$	98,691		$	104,409

Segment Income Taxes Segment income tax expenses for the years 2003, 2002 and 2001 are as follows:


	Year ended December 31
	2003¹			2002			2001

Exploration and Production
United States	$	1,867		$	862		$	965
International		3,867			3,433			3,569

Total Exploration and Production		5,734			4,295			4,534

Refining, Marketing and Transportation

United States		300			(254	)		744
International		275			138			260

Total Refining, Marketing and Transportation		575			(116	)		1,004

Chemicals
United States		(25	)		(17	)		(78	)
International		6			17			23

Total Chemicals		(19	)		–			(55	)

All Other²		(946	)		(1,155	)		(1,123	)

Total Income Tax Expense²	$	5,344		$	3,024		$	4,360

¹		See Note 25 on page FS-50 for information concerning the cumulative effect of changes in accounting principles due to the adoption of FAS 143, “Accounting for Asset Retirement Obligations.”
²		2001 excludes tax of $144 for extraordinary item.

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 14 beginning on page FS-38. Information related to properties, plant and equipment by segment is contained in Note 15 on page FS-40.

NOTE 10.

LITIGATION

Unocal Patent Chevron, Texaco and four other oil companies (refiners) filed suit in 1995, contesting the validity of a patent (‘393’ patent) granted to Unocal Corporation (Unocal) for certain reformulated gasoline blends. ChevronTexaco sells reformulated gasolines in California in certain months of the year.

In March 2000, the U.S. Court of Appeals for the Federal Circuit upheld a September 1998 District Court decision that Unocal’s patent was valid and enforceable and assessed damages of 5.75 cents per gallon for gasoline produced during the summer of 1996 that infringed on the claims of the patent.

In February 2001, the U.S. Supreme Court concluded it would not review the lower court’s ruling, and the case was sent back to the District Court for an accounting of all infringing gasoline produced after August 1, 1996. The District Court ruled that the per-gallon damages awarded by the jury are limited to infringement that occurs in California only. Additionally, the U.S. Patent and Trademark Office (USPTO) granted three petitions by the refiners to re-examine the validity of Unocal’s ‘393’ patent and has twice rejected all of the claims in the ‘393’ patent. Those rejections have been appealed by Unocal to the USPTO Board of Appeals. The District Court judge requested further briefing and advised that she would not enter a final judgment in this case until the USPTO had completed its re-examination of the ‘393’ patent.

During 2002 and 2003, the USPTO granted two petitions for re-examination of another Unocal patent, the ‘126’ patent. The USPTO has rejected the validity of the claims of the ‘126’ patent, which could affect a larger share of U.S. gasoline production. Separately, in March 2003, the Federal Trade Commission (FTC)

NOTE 10. LITIGATION — Continued

filed a complaint against Unocal alleging that its conduct during the pendency of the patents was in violation of antitrust law. In November 2003, the Administrative Law Judge dismissed the complaint brought by the FTC. The FTC has appealed the decision.

In 2000, prior to the merger, Chevron and Texaco made payments to Unocal totaling approximately $30 million for the original court ruling, including interest and fees.

Along with other oil companies, the company is a party to more than 60 lawsuits and claims related to the use of the chemical MTBE in certain oxygenated gasolines. These actions may require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future.

The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. ChevronTexaco has reduced the use of MTBE in gasoline it manufactures in the United States, including the complete phase-out of MTBE in California before the end of 2003.

NOTE 11.
LEASE COMMITMENTS

Certain noncancelable leases are classified as capital leases, and the leased assets are included as part of “Properties, plant and equipment, at cost.” Such leasing arrangements involve tanker charters, crude oil production and processing equipment, service stations, and other facilities. Other leases are classified as operating leases and are not capitalized. The payments on such leases are recorded as expense. Details of the capitalized leased assets are as follows:


	At December 31
	2003		2002

Exploration and Production	$	246	$	176
Refining, Marketing and Transportation		842		843

Total		1,088		1,019
Less: Accumulated amortization		642		595

Net capitalized leased assets	$	446	$	424

Rental expenses incurred for operating leases during 2003, 2002 and 2001 were as follows:


	Year ended December 31
	2003		2002		2001

Minimum rentals	$	1,567	$	1,270	$	1,132
Contingent rentals		3		4		14

Total		1,570		1,274		1,146
Less: Sublease rental income		48		53		76

Net rental expense	$	1,522	$	1,221	$	1,070

Contingent rentals are based on factors other than the passage of time, principally sales volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, renewal options ranging from one to 25 years, and/or options to purchase the leased property during or at the end of the initial or renewal lease period for the fair market value or other specified amount at that time.

At December 31, 2003, the estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases, which at inception had a noncancelable term of more than one year, were as follows:


	At December 31
	Operating		Capital
	Leases		Leases

Year: 2004	$	299	$	98
2005		288		66
2006		260		65
2007		206		58
2008		181		48
Thereafter		800		547

Total	$	2,034	$	882

Less: Amounts representing interest
and executory costs				269

Net present values				613
Less: Capital lease obligations
included in short-term debt				370

Long-term capital lease obligations			$	243

NOTE 12.
RESTRUCTURING AND REORGANIZATION COSTS

In connection with various reorganizations and restructurings across several businesses and corporate departments, during 2003 the company recorded before-tax charges of $258 ($146 after tax) for estimated termination benefits for approximately 4,500 employees. Nearly half of the liability related to the global downstream business, including the effect of its reorganization along functional lines rather than the geographic configuration used previously. Substantially all of the employee reductions are expected to occur by early 2005.

Activity for the company’s liability related to reorganizations and restructurings in 2003 is summarized in the following table:


Amounts before tax	Amount

Balance at January 1, 2003	$	6
Additions		258
Payments		(24	)

Balance at December 31, 2003	$	240

An approximate $100 liability remained for employee severance charges recorded in 2002 and 2001. The balance related primarily to deferred payment options elected by certain employees who terminated before the end of 2003 and were paid in January 2004.


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

NOTE 13.
ASSETS HELD FOR SALE

At December 31, 2003, the company classified $1,100 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. The asset dispositions are expected to occur during 2004, substantially all of which related to the U.S. upstream business segment.

These anticipated sales, consisting of interests in several hundred individual properties, relate to the company’s plan to dispose of certain assets in the overall portfolio that do not provide sufficient long-term value.

No significant gains or losses were recorded in 2003 for the held-for-sale assets. Revenues and earnings associated with the assets were likewise insignificant in 2003 and earlier years.

NOTE 14.
INVESTMENTS AND ADVANCES

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


	Investments and Advances				Equity in Earnings
	At December 31				Year ended December 31
	2003		2002		2003			2002			2001

Exploration and Production
Tengizchevroil	$	3,363	$	2,949	$	611		$	490		$	332
Other		991		876		200			116			205

Total Exploration and
Production		4,354		3,825		811			606			537

Refining, Marketing
and Transportation
Equilon*		–		–		–			–			274
Motiva*		–		–		–			–			276
LG-Caltex Oil Corporation		1,561		1,513		107			46			60
Caspian Pipeline Consortium		1,026		1,014		52			66			38
Star Petroleum Refining
Company Ltd.		457		449		8			(25	)		(56	)
Caltex Australia Ltd.		118		109		13			(156	)		16
Other		1,069		994		100			110			92

Total Refining, Marketing
and Transportation		4,231		4,079		280			41			700

Chemicals
Chevron Phillips Chemical
Company LLC		1,747		1,710		24			2			(229	)
Other		20		21		1			4			2

Total Chemicals		1,767		1,731		25			6			(227	)

All Other
Dynegy Inc.		698		347		(56	)		(679	)		188
Other		761		681		(31	)		1			(54	)

Total equity method	$	11,811	$	10,663	$	1,029		$	(25	)	$	1,144
Other at or below cost		508		434

Total investments and
advances	$	12,319	$	11,097

Total U.S.	$	3,905	$	3,216	$	175		$	(559	)	$	693

Total International	$	8,414	$	7,881	$	854		$	534		$	451


*	Placed in trust at the time of the merger and accounting changed from the equity method to the cost basis.

Descriptions of major affiliates are as follows:

Tengizchevroil ChevronTexaco has a 50 percent equity ownership interest in Tengizchevroil (TCO), a joint venture formed in 1993 to develop the Tengiz and Korolev oil fields in Kazakhstan over a 40-year period. Upon formation of the joint venture, the company incurred an obligation of $420, payable to the Republic of Kazakhstan upon attainment of a dedicated export system with the capability of the greater of 260,000 barrels of oil per day or TCO’s production capacity. As a part of the 2001 transaction, the company paid $210 of the $420 obligation. An additional $210 was paid in 2003 to settle the remaining obligation. The $420 was also included in the carrying value of the original investment, as the company believed, beyond a reasonable doubt, that its full payment would be made.

Equilon Enterprises LLC and Motiva Enterprises LLC Until February 2002, the company had equity interests in Equilon and Motiva – joint ventures engaged in U.S. refining and marketing activities. Under mandate of the FTC as a condition of the merger, the company’s ownership interests were placed in trust on October 9, 2001. The trust completed the dispositions of the company’s investments in Equilon and Motiva in February 2002. See Note 2 on page FS-30 for additional information on Equilon and Motiva.

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

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

Caltex Australia Ltd. ChevronTexaco has a 50 percent equity ownership interest in Caltex Australia Limited (CAL). The remaining 50 percent of CAL is publicly owned. During 2002, the company wrote down its investment in CAL by $136 to its estimated fair value at September 30, 2002. At December 31, 2003, the fair value of ChevronTexaco’s share of CAL common stock was $465. The aggregate carrying value of the company’s investment in CAL was approximately $90 lower than the amount of underlying equity in CAL net assets.

Chevron Phillips Chemical Company LLC ChevronTexaco owns 50 percent of CPChem, formed in July 2000 when Chevron merged most of its petrochemicals businesses with those of Phillips Petroleum Company. Because CPChem is a limited liability company, ChevronTexaco records the provision for income taxes and related tax liability applicable to its share of the venture’s income separately in its consolidated financial statements. At December 31, 2003, the company’s carrying value of its investment in CPChem was approximately $130 lower than the amount of underlying equity in CPChem’s net assets.

Dynegy Inc. ChevronTexaco owns an approximate 26 percent equity interest in the common stock of 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.

NOTE 14. INVESTMENTS AND ADVANCES – Continued

Investment in Dynegy Common Stock At December 31, 2003, the carrying value of the company’s investment in Dynegy common stock was approximately $150. This amount was about $425 below the company’s proportionate interest in Dynegy’s underlying net assets. This difference resulted from write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value that were deemed to be other than temporary. The approximate $425 difference has been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors giving rise to the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and Dynegy’s historical book values. The

market value of the company’s investment in Dynegy’s common stock at December 31, 2003 was $415.

Investments in Dynegy Notes and Preferred Stock Refer to Note 8 on page FS-34 for a discussion of these investments.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $6,308, $6,522 and $15,238 with affiliated companies for 2003, 2002 and 2001, respectively. “Purchased crude oil and products” includes $1,740, $1,839 and $4,069 with affiliated companies for 2003, 2002 and 2001, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $827 and $615 due from affiliated companies at December 31, 2003 and 2002, respectively. “Accounts payable” includes $118 and $161 due to affiliated companies at December 31, 2003 and 2002, respectively.

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


	Equilon¹						Motiva¹						Other Affiliates								ChevronTexaco Share^2,3
Year ended December 31	2003		2002		2001		2003		2002		2001		2003		2002			2001			2003		2002			2001

Total revenues	$	–	$	–	$	36,501	$	–	$	–	$	14,459	$	42,323	$	31,877		$	69,549		$	19,467	$	15,049		$	46,649
Income (loss) before
income tax expense		–		–		604		–		–		771		1,657		(1,517	)		646			1,211		70			1,430
Net income (loss)		–		–		397		–		–		486		1,508		(1,540	)		(74	)		1,029		(25	)		1,144

At December 31

Current assets	$	–	$	–	$	–	$	–	$	–	$	–	$	12,204	$	16,808		$	17,015		$	5,180	$	6,270		$	5,922
Noncurrent assets		–		–		–		–		–		–		39,422		40,884			40,191			15,765		15,219			16,276
Current liabilities		–		–		–		–		–		–		9,642		14,414			14,688			4,132		5,158			4,757
Noncurrent liabilities		–		–		–		–		–		–		22,738		24,129			23,255			5,002		5,668			5,600

Net equity	$	–	$	–	$	–	$	–	$	–	$	–	$	19,246	$	19,149		$	19,263		$	11,811	$	10,663		$	11,841


	At December 31												Year ended December 31
	Gross Investment at Cost						Net Investment²						Additions at Cost³						Depreciation Expense
	2003		2002		2001		2003		2002		2001		2003		2002		2001		2003		2002		2001

Exploration and Production
United States	$	34,798	$	39,986	$	38,582	$	9,953	$	10,457	$	10,560	$	1,776	$	1,658	$	1,973	$	1,815	$	1,806	$	3,508
International		37,402		36,382		33,273		20,572		18,908		17,743		3,246		3,343		2,900		2,227		2,132		2,085

Total Exploration
and Production		72,200		76,368		71,855		30,525		29,365		28,303		5,022		5,001		4,873		4,042		3,938		5,593

Refining, Marketing
and Transportation
United States		12,959		13,423		12,944		5,881		6,296		6,237		389		671		626		493		570		476
International		11,174		11,194		10,878		5,944		6,310		6,349		388		411		566		655		530		555

Total Refining, Marketing
and Transportation		24,133		24,617		23,822		11,825		12,606		12,586		777		1,082		1,192		1,148		1,100		1,031

Chemicals
United States		613		614		602		303		317		321		12		16		10		21		21		22
International		719		731		698		404		420		405		24		37		31		38		21		19

Total Chemicals		1,332		1,345		1,300		707		737		726		36		53		41		59		42		41

All Other⁴
United States		2,772		2,783		2,826		1,393		1,334		1,249		169		230		171		109		149		385
International		119		118		57		88		113		18		8		55		3		26		2		9

Total All Other		2,891		2,901		2,883		1,481		1,447		1,267		177		285		174		135		151		394

Total United States		51,142		56,806		54,954		17,530		18,404		18,367		2,346		2,575		2,780		2,438		2,546		4,391
Total International		49,414		48,425		44,906		27,008		25,751		24,515		3,666		3,846		3,500		2,946		2,685		2,668

Total	$	100,556	$	105,231	$	99,860	$	44,538	$	44,155	$	42,882	$	6,012	$	6,421	$	6,280	$	5,384	$	5,231	$	7,059

NOTE 16.
TAXES


	Year ended December 31
	2003		2002			2001

Taxes on income
U.S. federal
Current	$	1,147	$	(72	)	$	946
Deferred		121		(414	)		(643	)
State and local		133		21			276

Total United States		1,401		(465	)		579

International
Current		3,900		3,156			3,764
Deferred		43		333			17

Total International		3,943		3,489			3,781

Total taxes on income	$	5,344	$	3,024		$	4,360

In 2003, the before-tax income, including related corporate and other charges, for U.S. operations was $5,701, compared with a before-tax loss of $2,140 in 2002 and before-tax income of $1,778 in 2001. For international operations, before-tax income was $7,069, $6,296 and $6,513 in 2003, 2002 and 2001, respectively. U.S. federal income tax expense was reduced by $196, $208 and $202 in 2003, 2002 and 2001, respectively, for business tax credits.

The preceding table does not include a U.S. deferred tax benefit of $191 and a foreign deferred tax expense of $170 associ-

ated with the adoption of FAS 143, and the related cumulative effect of change in accounting principle.

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

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


	Year ended December 31
	2003			2002			2001

U.S. statutory federal income tax rate		35.0	%		35.0	%		35.0	%
Effect of income taxes from inter-
national operations in excess of
taxes at the U.S. statutory rate		12.1			29.6			19.0
State and local taxes on income, net
of U.S. federal income tax benefit		0.5			1.1			2.2
Prior-year tax adjustments		(1.6	)		(7.0	)		1.1
Tax credits		(1.5	)		(5.0	)		(2.4	)
Effects of enacted changes in tax
laws/rates on deferred tax liabilities		0.3			2.0			–
Impairment of investments in
equity affiliates		–			12.4			–
Other		(1.9	)		–			(1.7	)

Consolidated companies		42.9			68.1			53.2
Effect of recording income from
certain equity affiliates on an after-tax basis		(1.1	)		4.7			(0.6	)

Effective tax rate		41.8	%		72.8	%		52.6	%

NOTE 16. TAXES — Continued

In 2003, the effective tax rate was about 42 percent. The decrease in the effective tax rate in 2003 compared with 2002 resulted from a lower proportion of international taxable income, which is taxed at higher rates than U.S. taxable income, and the absence in 2003 of the 2002 tax effects of the capital losses discussed in the next paragraph.

The increase in the 2002 effective tax rate from 2001 was due to a number of factors. One reason was that U.S. before-tax income (generally subject to a lower tax rate) was a significantly smaller percentage of overall before-tax income in 2002. Another major factor was that the impairment of the investments in Dynegy and Caltex Australia were capital losses for which no offsetting capital gains were available.

The company records its deferred taxes on a tax-jurisdiction basis and classifies those net amounts as current or noncurrent based on the balance sheet classification of the related assets or liabilities.

The reported deferred tax balances are composed of the following:


	At December 31
	2003			2002

Deferred tax liabilities
Properties, plant and equipment	$	8,796		$	7,818
Inventory		(57	)		14
Investments and other		602			521

Total deferred tax liabilities		9,341			8,353

Deferred tax assets
Abandonment/environmental reserves		(1,221	)		(902	)
Employee benefits		(1,272	)		(1,414	)
Tax loss carryforwards		(956	)		(747	)
AMT/other tax credits		(352	)		(380	)
Other accrued liabilities		(199	)		(234	)
Miscellaneous		(2,034	)		(1,927	)

Total deferred tax assets		(6,034	)		(5,604	)

Deferred tax assets valuation allowance		1,553			1,740

Total deferred taxes, net	$	4,860		$	4,489

The valuation allowance relates to foreign tax credit carry-forwards, tax loss carryforwards and temporary differences for which no benefit is expected to be realized. The decrease in the valuation allowance relates primarily to the expiration of foreign tax credits and to the release of the valuation allowance on certain net operating losses, which management believes will now be realized. Tax loss carryforwards exist in many foreign jurisdictions and expire at various times beginning 2004 through 2010. However, some of these tax loss carryforwards do not have an expiration date.

At December 31, 2003 and 2002, deferred taxes were classified in the Consolidated Balance Sheet as follows:


	At December 31
	2003			2002

Prepaid expenses and other current assets	$	(940	)	$	(760	)
Deferred charges and other assets		(641	)		(455	)
Federal and other taxes on income		24			85
Noncurrent deferred income taxes		6,417			5,619

Total deferred income taxes, net	$	4,860		$	4,489

It is the company’s policy for subsidiaries included in the U.S. consolidated tax return to record income tax expense as though they filed separately, with the parent recording the adjustment to income tax expense for the effects of consolidation. Income taxes are accrued for retained earnings of international subsidiaries and corporate joint ventures intended to be remitted. Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely.

Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $10,541 at December 31, 2003. Substantially all of this amount represents earnings reinvested as part of the company’s ongoing business. It is not practicable to estimate the amount of taxes that might be payable on the eventual remittance of such earnings. On remittance, certain countries impose withholding taxes that, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any.

Taxes other than on income were as follows:


	Year ended December 31
	2003		2002		2001

United States
Excise taxes on products and merchandise	$	3,744	$	3,990	$	3,954
Import duties and other levies		11		12		8
Property and other
miscellaneous taxes		309		348		410
Payroll taxes		138		141		148
Taxes on production		244		179		225

Total United States		4,446		4,670		4,745

International
Excise taxes on products
and merchandise		3,351		3,016		2,592
Import duties and other levies		9,652		8,587		7,461
Property and other
miscellaneous taxes		320		291		268
Payroll taxes		54		46		79
Taxes on production		83		79		11

Total International		13,460		12,019		10,411

Total taxes other than on income	$	17,906	$	16,689	$	15,156

NOTE 17.
SHORT-TERM DEBT


	At December 31
	2003			2002

Commercial paper*	$	4,078		$	7,183
Notes payable to banks and others with
originating terms of one year or less		190			713
Current maturities of long-term debt		863			740
Current maturities of long-term
capital leases		71			45
Redeemable long-term obligations
Long-term debt		487			487
Capital leases		299			300

Subtotal		5,988			9,468
Reclassified to long-term debt		(4,285	)		(4,110	)

Total short-term debt	$	1,703		$	5,358

Weighted-average interest rates at December 31, 2003 and 2002, were 1.01 per- cent and 1.47 percent, respectively, including the effect of interest rate swaps.


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

NOTE 17. SHORT-TERM DEBT – Continued

Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.

The company periodically enters into interest rate swaps on a portion of its short-term debt. See Note 8 beginning on page FS-33 for information concerning the company’s debt-related derivative activities.

At December 31, 2003, the company had $4,285 of committed credit facilities with banks worldwide, which permit the company to refinance short-term obligations on a long-term basis. The facilities support the company’s commercial paper borrowings. Interest on borrowings under the terms of specific agreements may be based on the London Interbank Offered Rate or bank prime rate. No amounts were outstanding under these credit agreements during 2003 or at year-end.

At December 31, 2003 and 2002, the company classified $4,285 and $4,110, respectively, of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital in 2004, as the company has both the intent and the ability to refinance this debt on a long-term basis.

NOTE 18.
LONG-TERM DEBT

ChevronTexaco has three “shelf” registrations on file with the Securities and Exchange Commission that together would permit the issuance of $3,800 of debt securities pursuant to Rule 415 of the Securities Act of 1933. The company’s long-term debt outstanding at year-end 2003 and 2002 was as follows:


	At December 31
	2003			2002

3.5% guarantees due 2007	$	1,993		$	1,992
3.375% notes due 2008		749			–
6.625% notes due 2004		499			499
5.5% note due 2009		431			439
7.327% amortizing notes due 2014¹		360			410
8.11% amortizing notes due 2004²		240			350
6% notes due 2005		299			299
9.75% debentures due 2020		250			250
5.7% notes due 2008		220			224
8.5% notes due 2003		–			200
7.75% debentures due 2033		–			199
8.625% debentures due 2031		199			199
8.625% debentures due 2032		199			199
7.5% debentures due 2043		198			198
6.875% debentures due 2023		–			196
7.09% notes due 2007		150			150
8.25% debentures due 2006		150			150
8.625% debentures due 2010		150			150
8.875% debentures due 2021		150			150
Medium-term notes, maturing from 2003 to 2043 (7.1%)³		210			277
Other foreign currency obligations (4.4%)³		52			87
Other long-term debt (3.5%)³		730			678

Total including debt due within one year		7,229			7,296
Debt due within one year		(863	)		(740	)
Reclassified from short-term debt		4,285			4,110

Total long-term debt	$	10,651		$	10,666


¹	Guarantee of ESOP debt.
²	Debt assumed from ESOP in 1999.
³	Less than $150 individually; weighted-average interest rates at December 31, 2003.

Consolidated long-term debt maturing after December 31, 2003, is as follows: 2004 – $863; 2005 – $572; 2006 – $326; 2007 – $2,209; and 2008 – $1,044; after 2008 – $2,215.

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

NOTE 19.
NEW ACCOUNTING STANDARDS

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 amended ARB 51, “Consolidated Financial Statements,” and established standards for determining under what circumstances a variable interest entity (VIE) should be consolidated by its primary beneficiary. FIN 46 also requires disclosures about VIEs that the company is not required to consolidate but in which it has a significant variable interest. On December 17, 2003, the FASB issued FIN 46-R, which not only included amendments to FIN 46, but also required application of the interpretation to all affected entities no later than March 31, 2004, for calendar-year reporting companies. However, companies must have applied the interpretation to special-purpose entities by December 31, 2003. The adoption of FIN 46-R as it relates to special-purpose entities did not have a material impact on the company’s results of operations, financial position or liquidity, and the company does not expect a material impact upon its full adoption of the interpretation as of March 31, 2004.

NOTE 20.
ACCOUNTING FOR MINERAL INTERESTS INVESTMENT

The Securities and Exchange Commission (SEC) has questioned certain public companies in the oil, gas and mining industries as to the proper accounting for, and reporting of acquired contractual mineral interests under FASB Statement No. 141, “Business Combinations” (FAS 141), and FASB Statement No. 142, “Goodwill and Intangible Assets” (FAS 142). These accounting standards became effective for the company on July 1, 2001, and January 1, 2002, respectively.

NOTE 21.
EMPLOYEE BENEFIT PLANS

The company has defined benefit pension plans for many employees and provides for certain health care and life insurance plans for some active and qualifying retired employees. The company typically funds only those defined benefit plans where legal funding is required. In the United States, this includes all qualified tax-exempt plans subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not

NOTE 21. EMPLOYEE BENEFIT PLANS – Continued

typically fund domestic nonqualified tax-exempt pension plans or international pension plans that are not subject to legal funding requirements because contributions to these pension plans may be less tax efficient and investment returns may be less attractive than the company’s other investment alternatives.

The company’s annual contributions for medical and dental benefits are limited to the lesser of actual medical and dental claims or a defined fixed per-capita amount. Life insurance benefits are paid by the company and annual contributions are based on actual plan experience.

The company uses a measurement date of December 31 to value its pension and other postretirement benefit plan obligations.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became law.

The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans, such as the company, that provide a benefit that is at least actuarially equivalent to Medicare Part D. The company is currently evaluating the impact of the legislation to its benefit plan design and accounting. The company has elected, in accordance with FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” to defer recognition of the Act in the company’s measurement of the accumulated postretirement benefit obligation and net postretirement benefit cost in its financial statements and the accompanying notes. Specific accounting guidance for the federal subsidy is pending and, when issued, could require the company to change previously reported information.

The status of the company’s pension and other postretirement benefit plans for 2003 and 2002 is as follows:


	Pension Benefits
	2003						2002						Other Benefits
	U.S.			Int'l.			U.S.			Int'l.			2003			2002

CHANGE IN BENEFIT OBLIGATION
Benefit obligation at January 1	$	5,308		$	2,163		$	5,180		$	1,848		$	2,865		$	2,526
Service cost		144			54			112			47			28			25
Interest cost		334			151			334			143			191			178
Plan participants’ contribution		1			1			2			3			–			–
Plan amendments		–			25			298			9			–			–
Actuarial loss		708			223			410			36			254			307
Foreign currency exchange rate changes		–			257			–			154			7			5
Benefits paid		(676	)		(162	)		(1,028	)		(123	)		(200	)		(176	)
Curtailment		–			(4	)		–			–			–			–
Acquisitions/joint ventures		–			–			–			46			–			–

Benefit obligation at December 31		5,819			2,708			5,308			2,163			3,145			2,865

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1		3,190			1,645			4,400			1,547			–			–
Actual return on plan assets		726			203			(284	)		(139	)		–			–
Foreign currency exchange rate changes		–			228			–			179			–			–
Employer contributions¹		1,203			214			100			146			200			176
Plan participants’ contributions		1			1			2			1			–			–
Benefits paid¹		(676	)		(162	)		(1,028	)		(123	)		(200	)		(176	)
Acquisitions/joint ventures		–			–			–			34			–			–

Fair value of plan assets at December 31		4,444			2,129			3,190			1,645			–			–

FUNDED STATUS		(1,375	)		(579	)		(2,118	)		(518	)		(3,145	)		(2,865	)
Unrecognized net actuarial loss		1,598			918			1,686			793			656			414
Unrecognized prior-service cost		350			92			363			74			(19	)		(21	)
Unrecognized net transitional assets		–			8			–			(1	)		–			–

Total recognized at December 31	$	573		$	439		$	(69	)	$	348		$	(2,508	)		(2,472	)

AMOUNTS RECOGNIZED IN THE CONSOLIDATED
BALANCE SHEET AT DECEMBER 31
Prepaid benefit cost	$	10		$	679		$	164		$	652		$	–		$	–
Accrued benefit liability		(970	)		(392	)		(1,928	)		(324	)		(2,508	)		(2,472	)
Intangible asset		349			18			360			8			–			–
Accumulated other comprehensive income²		1,184			134			1,335			12			–			–

Net amount recognized³	$	573		$	439		$	(69	)	$	348		$	(2,508	)	$	(2,472	)

WEIGHTED-AVERAGE ASSUMPTIONS USED TO
DETERMINE BENEFIT OBLIGATIONS AS OF DECEMBER 31
Discount rate		6.0	%		6.8	%		6.8	%		7.1	%		6.1	%		6.8	%
Rate of compensation increase		4.0	%		4.9	%		4.0	%		5.1	%		4.1	%		4.1	%


¹	Amounts for 2002 conformed to 2003 presentation to include company contributions and benefits paid for nonqualified plans.
²	“Accumulated other comprehensive income” includes deferred income taxes of $415 and $47 in 2003 for U.S. and International, respectively, and $467 and $4 in 2002 for U.S. and International, respectively. This item is presented net of these taxes in the Consolidated Statement of Stockholders’ Equity.
³	The company recorded additional minimum pension liabilities of $1,533 and $152 in 2003 for U.S. and International, respectively, and 20 in 2002 for U.S. $1,695 and $ and International, respectively, to reflect the amount of unfunded accumulated benefit obligations. The additional minimum pension liabilities are offset by intangible assets and a charge to “Accumulated other comprehensive income. ” Accrued liabilities also reflect net minimum liabilities for plans with prepaid benefit costs and additional minimum liabilities.


	Pension Benefits
	2003						2002						2001						Other Benefits
	U.S.			Int'l.			U.S.			Int'l.			U.S.			Int'l.			2003			2002			2001

Service cost	$	144		$	54		$	112		$	47		$	111		$	47		$	28		$	25		$	21
Interest cost		334			151			334			143			355			136			191			178			165
Expected return on plan assets		(224	)		(132	)		(288	)		(138	)		(443	)		(170	)		–			–			–
Amortization of transitional assets		–			(3	)		–			(3	)		(2	)		(4	)		–			–			–
Amortization of prior-service costs		45			14			32			12			25			12			(3	)		(3	)		(1	)
Recognized actuarial losses (gains)		133			42			32			27			13			7			12			(1	)		(6	)
Settlement losses		132			1			146			1			12			–			–			–			–
Curtailment losses		–			6			–			–			26			–			–			–			20
Special termination benefit
recognition		–			–			–			–			47			14			–			–			29

Net periodic benefit cost	$	564		$	133		$	368		$	89		$	144		$	42		$	228		$	199		$	228

Weighted-average assumptions used to
determine net cost as of December 31
Discount rate*		6.3	%		7.1	%		7.4	%		7.7	%		7.5	%		7.8	%		6.8	%		7.3	%		7.6	%
Expected return on plan assets*		7.8	%		8.3	%		8.3	%		8.9	%		9.6	%		9.1	%		N/A			N/A			N/A
Rate of compensation increase		4.0	%		5.1	%		4.0	%		5.4	%		4.1	%		5.0	%		4.1	%		4.1	%		4.4	%

The company employs a rigorous process to determine the estimates of long-term rate of return on pension assets. These estimates are primarily driven by actual historical asset-class returns and advice from external actuarial firms while incorporating specific asset-class risk factors. Asset allocations are regularly updated using pension plan asset/liability studies, and the determination of the company’s estimates of long-term rates of return are consistent with these studies.

At December 31, 2003, the estimated long-term rate of return on U.S. pension plan assets, which account for about 70 percent of the company’s pension plan assets, was 7.8 percent, compared with rates of 7.8 and 9.0 percent at the end of 2002 and 2001, respectively. The year-end market-related value of U.S. pension plan assets used in the determination of pension expense was based on the market values in the preceding three months, as opposed to the maximum allowable period of five years under U.S. accounting rules. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and yet still be contemporaneous to the end of the year.

The asset allocation for the company’s primary U.S. pension plans at the end of 2003 and 2002 and the target allocation, by asset category, are:


	Board-			Policy			Actual
	Approved			Benchmark			Percentage
	Asset			Asset			of Plan Assets
	Allocation			Allocation			at Year-End
Asset Category							2003			2002

Equities		40-70	%		60	%		70	%		63	%
Fixed Income		20-60	%		30	%		21	%		26	%
Real Estate		0-15	%		10	%		8	%		10	%
Other		0- 5	%		N/A			1	%		1	%

Total		N/A			100	%		100	%		100	%

The U.S. pension plans invest primarily in asset categories with sufficient size, liquidity and cost efficiency to permit investments of reasonable size. The U.S. pension plans invest in asset categories that provide diversification benefits and are easily measured. Maximum and minimum holding ranges for each of these asset categories are set by the ChevronTexaco Board of Directors for the primary U.S. pension plan. Actual asset allocation within these approved ranges is based on a variety of economic and market conditions and consideration of specific asset category risk. To assess the plan’s investment performance, a long-term asset allocation policy benchmark has been established.

Equities include investments in the company’s common stock in the amount of $6 and $4 at December 31, 2003 and 2002, respectively. The “Other” asset category includes minimal investments in private equity limited partnerships.

In early 2004, the company contributed about $535 to the U.S. plans. Additionally, the company anticipates contributing

NOTE 21. EMPLOYEE BENEFIT PLANS — Continued

about $50 to the U.S. plans during the remainder of the year. In 2003, contributions to the U.S. plans totaled $1,203. In years subsequent to 2004, the company expects contributions to be approximately $250 per year, about equal to the cost of benefits earned in that year. Contributions in 2004 to the international pension plans are estimated at $200, while 2003 contributions were $214. The actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors.

The company anticipates funding U.S. other postretirement benefits $210 in 2004, compared with $197 in 2003.

For postretirement benefit measurement purposes in 2003, health care costs were assumed to increase approximately 8.4 percent over the previous year, and the trend rates gradually drop to 4.5 percent for 2007 and beyond.


	Assumed health care
	trend rates at December 31
	2003			2002

U.S. health care cost-trend rate		8.4	%		12.0	%
Rate to which the cost trend is assumed
to decline (the ultimate trend rate)		4.5	%		4.5	%
Year that the rate reaches the ultimate rate		2007			2007

Assumed health care cost-trend rates have a significant effect on the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have the following effects:


	1 Percent		1 Percent
	Increase		Decrease

Effect on total service and
interest cost components	$	26	$	(21	)
Effect on postretirement benefit obligation	$	321	$	(266	)

Employee Savings Investment Plan Eligible employees of ChevronTexaco and certain of its subsidiaries participate in the ChevronTexaco Employee Savings Investment Plan (ESIP). In 2002, the Employees Thrift Plan of Texaco Inc., Employees Savings Plan of ChevronTexaco Global Energy Inc. (formerly Caltex Corporation), Stock Plan of ChevronTexaco Global Energy Inc. and Employees Thrift Plan of Fuel and Marine Marketing LLC were merged into the ChevronTexaco ESIP. Charges to expense for these plans were $160, $161 and $157 in 2003, 2002 and 2001, respectively.

Employee Stock Ownership Plans (ESOP) Within the Chevron-Texaco Employee Savings Investment Plan, the company has established an employee stock ownership plan. In 1989, Chevron established a leveraged employee stock ownership plan (LESOP) as a constituent part of the ESOP. The LESOP provides partial prefunding of the company’s future commitments to the ESIP, which will result in annual income tax savings for the company.

In 1988, Texaco established a leveraged employee stock ownership plan as a component of the Employees Thrift Plan of Texaco Inc. During 2002, the Employees Thrift Plan of Texaco Inc. was subsumed into the ChevronTexaco ESIP.

As permitted by American Institute of Certified Public Accountants (AICPA) Statement of Position 93-6, “Employers’ Accounting for Employee Stock Ownership Plans,” the company has elected to continue its practices, which are based on Statement of Position 76-3, “Accounting Practices for Certain

Employee Stock Ownership Plans,” and subsequent consensus of the Emerging Issues Task Force of the Financial Accounting Standards Board. The debt of the LESOPs is recorded as debt, and shares pledged as collateral are reported as “Deferred compensation and benefit plan trust” in the Consolidated Balance Sheet and the Consolidated Statement of Stockholders’ Equity.

The company reports compensation expense equal to LESOP debt principal repayments less dividends received by the LESOPs. Interest incurred on the LESOP debt is recorded as interest expense. Dividends paid on LESOP shares are reflected as a reduction of retained earnings. All LESOP shares are considered outstanding for earnings-per-share computations.

Expense recorded for the LESOPs was $24, $98 and $75 in 2003, 2002 and 2001, respectively, including $28, $32 and $43 of interest expense related to LESOP debt. All dividends paid on the LESOP shares held are used to service the LESOP debt. The dividends used were $61, $49 and $86 in 2003, 2002 and 2001, respectively.

The company made LESOP contributions of $26, $102 and $75 in 2003, 2002 and 2001, respectively, to satisfy LESOP debt service in excess of dividends received by the LESOP. The LESOP shares were pledged as collateral for the debt. Shares are released from a suspense account and allocated to the accounts of plan participants, based on the debt service deemed to be paid in the year in proportion to the total of current-year and remaining debt service. The (credit) charge to compensation expense was $(4), $66 and $32 in 2003, 2002 and 2001, respectively. LESOP shares as of December 31, 2003 and 2002, were as follows:


Thousands	2003		2002

Allocated shares		12,099		12,513
Unallocated shares*		6,817		7,614

Total LESOP shares		18,916		20,127


*	2002 restated to conform to 2003 presentation.

Benefit Plan Trust Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2003, the trust contained 7.1 million shares of ChevronTexaco treasury stock. The company intends to continue to pay its obligations under the benefit plans. The trust will sell the shares or use the dividends from the shares to pay benefits only to the extent that the company does not pay such benefits. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The shares held in the trust are not considered outstanding for earnings-per-share purposes until distributed or sold by the trust in payment of benefit obligations.

Management Incentive Plans ChevronTexaco has two incentive plans, the Management Incentive Plan (MIP) and the Long-Term Incentive Plan (LTIP) for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. The plans were expanded in 2002 to include former employees of Texaco and Caltex. The MIP is an annual cash incentive plan that links awards to performance results of the prior year. The cash awards may be deferred by conversion to stock units or other investment fund alternatives. Awards under the LTIP may take the form of, but are not limited to, stock options, restricted stock, stock units and nonstock grants. Texaco also had a cash incentive program and a Stock Incentive Plan (SIP) that included stock options, restricted stock and other incentive awards for executives, directors and key employees. Awards under the Caltex LTIP were in the form of performance units and stock appreciation rights. Charges to


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

NOTE 21. EMPLOYEE BENEFIT PLANS — Continued

expense for the combined management incentive plans, excluding expense related to LTIP and SIP stock options and restricted stock awards that are discussed in Note 22, below, were $148, $48 and $101 in 2003, 2002 and 2001, respectively.

Other Incentive Plans The company has a program that provides eligible employees with an annual cash bonus if the company achieves certain financial and safety goals. Charges for the program were $151, $158 and $154 in 2003, 2002 and 2001, respectively.

NOTE 22.
STOCK OPTIONS

The company applies APB Opinion No. 25 and related interpretations in accounting for its stock-based compensation programs, which are described below. Stock-based compensation expense (credit) recognized in connection with these programs was $2, $(2) and $111 in 2003, 2002 and 2001, respectively.

Refer to Note 1 on page FS-30 for the pro forma effect on net income and earnings per share had the company applied the fair-value-recognition provisions of FAS No. 123.

Broad-Based Employee Stock Options In 1998, Chevron granted to all its eligible employees an option that varied from 100 to 300 shares of stock or equivalents, dependent on the employee’s salary or job grade. These options vested after two years in February 2000. Options for 4,820,800 shares were awarded at an exercise price of $76.3125 per share. Outstanding option shares were 2,366,311 at the end of 2001. In 2002, exercises of 295,985 and forfeitures of 61,151 reduced the outstanding option shares to 2,009,175 at the end of the year. In 2003, exercises of 11,630 and forfeitures of 61,050 reduced the outstanding option shares to 1,936,495 at the end of the year. The options expire in February 2008. The company recorded expense (credit) of $2, $(2) and $1 for these options in 2003, 2002 and 2001, respectively.

The fair value of each option share on the date of grant under FAS No. 123 was estimated at $19.08 using the average results of Black-Scholes models for the preceding 10 years. The 10-year averages of each assumption used by the Black-Scholes models were: a risk-free interest rate of 7.0 percent, a dividend yield of 4.2 percent, an expected life of seven years and a volatility of 24.7 percent.

Long-Term Incentive Plan Stock options granted under the LTIP extend for 10 years from the date of grant. Effective with options granted in June 2002, one third of the options vest on each of the first, second and third anniversaries of the date of grant. Prior to this change, options granted by Chevron vested one year after the date of grant, whereas options granted by Texaco under its SIP vested over a two-year period at a rate of 50 percent each year. The maximum number of shares that may be granted each year is 1 percent of the total outstanding shares of common stock as of January 1 of such year.

On the closing of the merger in October 2001, outstanding options granted under the Texaco SIP were converted to ChevronTexaco options at the merger exchange rate of 0.77. These options retained a provision for restored options. This feature enables a participant who exercises a stock option by exchanging previously acquired common stock or who has shares withheld to satisfy tax withholding obligations to receive new

options equal to the number of shares exchanged or withheld. The restored options are fully exercisable six months after the date of grant, and the exercise price is the fair market value of the common stock on the day the restored option is granted. Restricted shares granted under the former Texaco plan contained a performance element that had to be satisfied in order for all or a specified portion of the shares to vest. Upon the merger, all restricted shares became vested and converted to ChevronTexaco shares at the merger exchange ratio of 0.77. Apart from the restored options, no further awards may be granted under the former Texaco plans. No amount for these plans was charged to compensation expense in 2003 or 2002; $110 of expense was recorded in 2001. Restricted performance shares granted under SIP in 2001 totaled 392,000 at an average fair value of $91.05 per share.

The fair market value of each stock option granted is estimated on the date of grant under FAS No. 123 using the Black-Scholes option-pricing model with the following weighted-average assumptions:


	2003			2002			2001

ChevronTexaco plans:
Expected life in years		7			7			7
Risk-free interest rate		3.1	%		4.6	%		4.1	%
Volatility		19.3	%		21.6	%		24.4	%
Dividend yield		3.5	%		3.0	%		3.0	%
Texaco plans:
Expected life in years		2			2			2
Risk-free interest rate		1.7	%		1.6	%		3.9	%
Volatility		22.0	%		24.1	%		25.9	%
Dividend yield		3.9	%		3.1	%		3.1	%

The Black-Scholes weighted-average fair value of the ChevronTexaco options granted during 2003, 2002 and 2001 was $11.02, $18.59 and $20.45 per share, respectively, and the weighted-average fair value of the SIP restored options granted during 2003 and 2002 and the Texaco options granted during 2001 was $8.06, $10.29 and $12.90 per share.

A summary of the status of stock options awarded under the company’s LTIP, as well as the former Texaco plans, for 2003, 2002 and 2001 follows:


	Options			Weighted-Average
	(thousands)			Exercise Price

Outstanding at December 31, 2000		20,870		$	75.67

Granted		3,777			89.84
Exercised		(8,209	)		78.16
Restored		6,766			89.77
Forfeited		(584	)		85.76

Outstanding at December 31, 2001		22,620		$	81.13

Granted		3,291			86.15
Exercised		(1,818	)		73.01
Restored		1,274			89.38
Forfeited		(745	)		88.10

Outstanding at December 31, 2002		24,622		$	82.66

Granted		4,660			73.39
Exercised		(729	)		50.15
Restored		60			82.69
Forfeited		(983	)		85.41

Outstanding at December 31, 2003		27,630		$	81.85

Exercisable at December 31
2001		19,028		$	79.64
2002		21,445		$	82.14
2003		21,277		$	83.23

NOTE 22. STOCK OPTIONS — Continued

The following table summarizes information about stock options outstanding, including those from former Texaco plans, at December 31, 2003:


Options Outstanding							Options Exercisable
			Weighted-
			Average		Weighted-				Weighted-
	Number		Remaining		Average		Number		Average
Range of	Outstanding		Contractual		Exercise		Exercisable		Exercise
Exercise Prices	(thousands)		Life (years)		Price		(thousands)		Price

$ 41 to $ 51		1,217		1.1	$	46.02		1,217	$	46.02
51 to 61		23		2.8		56.24		23		56.24
61 to 71		683		2.8		66.26		683		66.26
71 to 81		8,554		7.1		76.15		4,114		79.11
81 to 91		13,305		6.1		86.82		11,392		86.93
91 to 101		3,848		5.8		91.61		3,848		91.61

$ 41 to $ 101		27,630		6.1	$	81.85		21,277	$	83.23

NOTE 23.
OTHER CONTINGENCIES AND COMMITMENTS

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

Guarantees At December 31, 2003, the company and its subsidiaries provided guarantees, either directly or indirectly, of $917 for notes and other contractual obligations of affiliated companies and $256 for third parties, as discussed, by major category, below. There are no amounts being carried as liabilities for the company’s obligations under these guarantees. Of the $917 guarantees provided to affiliates, $716 related to borrowings for capital projects or general corporate purposes. These guarantees were undertaken to achieve lower interest rates and generally cover the construction period of the capital projects. Approximately 75 percent of the amounts guaranteed will expire in 2004, with the remaining guarantees expiring by the end of 2015. Under the terms of the guarantees, the company would be required to fulfill the guarantee should an affiliate be in default of its loan terms, generally for the full amounts disclosed. There are no recourse provisions, and no assets are held as collateral for these guarantees.

Another $201 of the affiliate guarantees related to obligations in connection with pricing of power purchase agreements for certain of the company’s cogeneration affiliates. Under the terms of these guarantees, the company may be required to make payments under certain conditions if the affiliates do not perform under the agreements. There are no provisions for recourse to third parties, and no assets are held as collateral for these pricing guarantees.

Guarantees of $256 have been provided to third parties, including approximately $110 of construction loans to host governments in the company’s international upstream operations. The other $146 was provided principally as conditions of sale of the company’s interest in certain operations, to provide a source of liquidity to the guaranteed parties and in connection with company marketing programs. No amounts of the company’s obligations under these guarantees are recorded as liabilities. About 75 percent of the total amounts guaranteed will expire in 2004, with the remainder expiring after 2004. The company would be required to perform under the terms of the guarantees should an entity be in default of its loan or contract terms, generally for the full amounts disclosed. Approximately $100 of the guarantees have recourse provisions, which enable the company to recover any payments made under the terms of the guarantees from securities held over the guaranteed parties’ assets.

At December 31, 2003, ChevronTexaco had outstanding guarantees for approximately $238 of Equilon debt and leases. Following the February 2002 disposition of its interest in Equilon, the company received an indemnification from Shell Oil Company for any claims arising from the guarantees. The company has not recorded a liability for these guarantees. Approximately 50 percent of the amounts guaranteed will expire within the 2004-2008 period, with the guarantees of the remaining amounts expiring by 2019.

Indemnities The company also provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell Oil Company (Shell) and Saudi Refining Inc. in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover general contingent liabilities, including those associated with the Unocal patent litigation. The company would be required to perform should the indemnified liabilities become actual losses and could be required to make maximum future payments of $300. The company has paid approximately $28 under these contingencies and has disputed approximately $34 in claims submitted by Shell under these indemnities. Shell requested arbitration of this dispute, and it is expected to occur in mid-2004. There are no recourse provisions enabling recovery of any amounts from third parties nor are any assets held as collateral. Within five years of the February 2002 sale, at the buyer’s option, the company also may be required to purchase certain assets from Shell for their net book value, as determined at the time of the company’s purchase. Those assets consist of 12 separate lubricant facilities, two of which were tendered to and purchased by the company in late 2003 for a de minimis price.

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


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

NOTE 23. OTHER CONTINGENCIES AND COMMITMENTS — Continued

Securitization The company securitizes certain retail and trade accounts receivable in its downstream business through the use of qualifying special purpose entities (SPEs). At December 31, 2003, approximately $1,000, representing about 11 percent of ChevronTexaco’s total current accounts receivables balance, were securitized. ChevronTexaco’s total estimated financial exposure under these arrangements at December 31, 2003, was approximately $75. These arrangements have the effect of accelerating ChevronTexaco’s collection of the securitized amounts. In the event of the SPEs experiencing major defaults in the collection of receivables, ChevronTexaco believes that it would have no loss exposure connected with third-party investments in these securitization arrangements.

Long-Term Unconditional Purchase Obligations and Commitments, Throughput Agreements, and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, throughput agreements, and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate amounts of required payments under these various commitments are 2004 — $1,200; 2005 — $1,100; 2006 — $1,000; 2007 — $1,000; 2008 — $1,000; 2009 and after — $1,900. Total payments under the agreements were $1,400 in 2003, $1,200 in 2002 and $1,500 in 2001. The most significant take-or-pay agreement calls for the company to purchase approximately 55,000 barrels per day of refined products from an equity affiliate refiner in Thailand. This purchase agreement is in conjunction with the financing of a refinery owned by the affiliate and expires in 2009. The future estimated commitments under this contract are: 2004 — $700; 2005 — $800; 2006 — $800; 2007 — $800; 2008 — $800 and 2009 — $800.

Minority Interests The company has commitments related to preferred shares of subsidiary companies, which are accounted for as minority interest. Texaco Capital LLC, a wholly owned finance subsidiary, has issued $65 of Deferred Preferred Shares, Series C. Dividends amounting to $60 on Series C, at a rate of 7.17 percent compounded annually, will be paid at the redemption date in February 2005, unless earlier redemption occurs. Early redemption may result upon the occurrence of certain specific events. MVP Production Inc., a subsidiary, redeemed variable rate cumulative preferred shares of $75 owned by one minority holder during 2003.

Environmental The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemical or petroleum substances, including MTBE, by the

company or other parties. Such contingencies may exist for various sites, including but not limited to: Superfund sites and refineries, oil fields, service stations, terminals, and land development areas, whether operating, closed or sold. The amount of such future cost is indeterminable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. While the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemicals concerns.

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

Equity Redetermination For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated oil and gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for ChevronTexaco’s interests in four producing zones at the

NOTE 23. OTHER CONTINGENCIES AND COMMITMENTS – Continued

Naval Petroleum Reserve at Elk Hills, California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. ChevronTexaco currently estimates its maximum possible net before-tax liability at approximately $200. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at about $50. The timing of the settlement and the exact amount within this range of estimates is uncertain.

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

The company and its affiliates also continue to review and analyze their operations and may close, abandon, sell, exchange, acquire or restructure assets to achieve operational or strategic

benefits and to improve competitiveness and profitability. These activities, individually or together, may result in gains or losses in future periods.

NOTE 24.
EARNINGS PER SHARE

Basic earnings per share (EPS) is based upon net income less preferred stock dividend requirements and includes the effects of deferrals of salary and other compensation awards that are invested in ChevronTexaco stock units by certain officers and employees of the company and the company’s share of stock transactions of affiliates, which, under the applicable accounting rules may be recorded directly to the company’s retained earnings instead of net income. Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (see Note 22, “Stock Options” on pages FS-46 and FS-47). The following table sets forth the computation of basic and diluted EPS:


2003									2002							2001
	Net			Shares		Per-Share				Net		Shares		Per-Share			Net			Shares		Per-Share
	Income			(millions)		Amount				Income		(millions)		Amount			Income			(millions)		Amount

Basic EPS Calculation
Net Income Before Extraordinary Items and Cumulative Effect of Changes in Accounting Principles	$	7,426								$	1,132						$	3,931
Weighted-average common shares outstanding					1,061.6								1,060.7								1,059.3
Dividend equivalents paid on ChevronTexaco stock units		2									3							2
Deferred awards held as ChevronTexaco stock units					0.9								0.8								0.8
Affiliate stock transactions recorded to retained earnings¹		170									–							–
Preferred stock dividends		–									–							(6	)

Net Income Before Extraordinary Items and Cumulative Effect of Changes in Accounting Principles – Basic	$	7,598			1,062.5	$	7.15			$	1,135		1,061.5	$	1.07		$	3,927			1,060.1	$	3.71
Extraordinary item²		–									–							(643	)				(0.61	)
Cumulative effect of changes in accounting principles³		(196	)				(0.18	)			–							–

Net Income – Basic	$	7,402			1,062.5	$	6.97			$	1,135		1,061.5	$	1.07		$	3,284			1,060.1	$	3.10

Diluted EPS Calculation
Net Income Before Extraordinary Items and Cumulative Effect of Changes in Accounting Principles – Basic	$	7,598			1,062.5					$	1,135		1,061.5				$	3,927			1,060.1
Dilutive effects of stock options, restricted stock and convertible debentures		2			1.5						2		1.9					4			2.8

Net Income Before Extraordinary Items and Cumulative Effect of Changes in Accounting Principles – Diluted	$	7,600			1,064.0	$	7.14			$	1,137		1,063.4	$	1.07			3,931			1,062.9	$	3.70
Extraordinary item²		–									–							(643	)				(0.61	)
Cumulative effect of changes in accounting principles³		(196	)				(0.18	)			–							–

Net Income – Diluted	$	7,404			1,064.0	$	6.96			$	1,137		1,063.4	$	1.07		$	3,288			1,062.9	$	3.09


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

NOTE 25.
FAS 143 — ASSET RETIREMENT OBLIGATIONS

The company adopted Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143), effective January 1, 2003. This accounting standard applies to the fair value of a liability for an asset retirement obligation that is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Obligations associated with the retirement of these assets require recognition in certain circumstances: (1) the present value of a liability and offsetting asset for an asset retirement obligation (ARO), (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates. FAS 143 primarily affects the company’s accounting for oil and gas producing assets and differs in several respects from previous accounting under FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.”

In the first quarter 2003, the company recorded a net after-tax charge of $200 for the cumulative effect of the adoption of FAS 143, including the company’s share of amounts attributable to equity affiliates. The cumulative-effect adjustment also increased the following balance sheet categories: “Properties, plant and equipment,” $2,568; “Accrued liabilities,” $115; and “Deferred credits and other noncurrent obligations,” $2,674. “Noncurrent deferred income taxes” decreased by $21.

Upon adoption, no significant legal obligations to retire refining, marketing and transportation (downstream) and chemical long-lived assets generally were recognized, as indeterminate settlement dates for the asset retirements prevented estimation of the fair value of the associated ARO. The company performs periodic reviews of its downstream and chemical long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.

Other than the cumulative-effect net charge, the effect of the new accounting standard on net income in 2003 was not materially different from what the result would have been under FAS 19 accounting. Included in “Depreciation, depletion and amortization” were $52 related to the depreciation of the ARO asset and $132 related to the accretion of the ARO liability.

The following table illustrates what the company’s net income before extraordinary items, net income and related per share amounts would have been if the provisions of FAS 143 had been applied retroactively:


	Year Ended December 31
		2003			2002			2001

Proforma net income before extraordinary items	$	7,430	¹	$	1,137	²	$	3,933	²
Earnings per share — basic³	$	7.15		$	1.07		$	3.71
Earnings per share — diluted³	$	7.14		$	1.07		$	3.70
Proforma net income	$	7,430	¹	$	1,137	²	$	3,290	²
Earnings per share — basic⁴	$	7.15		$	1.07		$	3.10
Earnings per share — diluted⁴	$	7.14		$	1.07		$	3.09

¹		Amount excludes cumulative-effect charge of $200 ($0.18 per basic and diluted share) for the adoption of FAS 143.
²		Includes benefit of $5 and $2 for 2002 and 2001, respectively, which represent the reversal of FAS 19 depreciation related to abandonment offset partially by proforma expenses for the depreciation and accretion of the ARO asset and liability, net of tax. There is a de minimis effect to net income per basic or diluted share.
³		Reported net income before extraordinary items was $1.07 per basic and diluted share for 2002 and $3.71 per basic share ($3.70 — diluted) for 2001.
⁴		Reported net income was $1.07 per basic and diluted share for 2002 and $3.10 per basic share ($3.09 — diluted) for 2001.

Prior to the implementation of FAS 143, the company had recorded a provision for abandonment that was part of “Accumulated depreciation, depletion and amortization.” Upon implementation of FAS 143, the provision for abandonment was reversed and ARO liability was recorded. The amount of the abandonment reserve at the end of each year and the proforma ARO liability were as follows:


		2003		2002		2001

ARO liability (FAS 143) at January 1	$	2,797	$	2,792	$	2,729
ARO liability (FAS 143) at December 31		2,856		2,797		2,792
Abandonment provision (FAS 19) at December 31		—		2,263		2,155

The following table indicates the changes to the company’s before-tax asset retirement obligations in 2003:


		2003

Balance at Jan. 1 — Cumulative effect of the accounting change	$	2,797
Liabilities incurred		14
Liabilities settled		(128	)
Accretion expense		132
Revisions in estimated cash flows		41

Balance at December 31	$	2,856


	2003											2002
Millions of dollars, except per-share amount	4TH Q		3RD Q			2ND Q			1ST Q			4TH Q			3RD Q			2ND Q			1ST Q

REVENUES AND OTHER INCOME
Sales and other operating revenues¹	$	30,132	$	30,163		$	29,085		$	30,652		$	26,943		$	25,681		$	25,223		$	20,844
Income (loss) from equity affiliates		262		287			215			265			111			(329	)		81			112
Gain from exchange of Dynegy securities		–		365			–			–			–			–			–			–
Other income		71		155			61			48			4			15			29			199

TOTAL REVENUES AND OTHER INCOME		30,465		30,970			29,361			30,965			27,058			25,367			25,333			21,155

COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products		17,964		18,007			17,337			18,275			15,871			14,871			14,694			11,813
Operating expenses		2,512		2,321			1,782			1,938			2,279			2,118			1,699			1,752
Selling, general and administrative expenses		1,173		1,197			1,061			1,009			1,107			1,032			1,153			863
Exploration expenses		139		130			147			155			205			166			135			85
Depreciation, depletion and amortization		1,322		1,409			1,411			1,242			1,271			1,514			1,241			1,205
Write-down of investments in Dynegy Inc.		–		–			–			–			–			1,094			702			–
Merger-related expenses		–		–			–			–			163			111			119			183
Taxes other than on income¹		4,645		4,418			4,513			4,330			4,403			4,369			4,137			3,780
Interest and debt expense		111		115			118			130			141			117			160			147
Minority interests		14		24			20			22			22			13			10			12

TOTAL COSTS AND OTHER DEDUCTIONS		27,880		27,621			26,389			27,101			25,462			25,405			24,050			19,840

INCOME BEFORE INCOME TAX EXPENSE		2,585		3,349			2,972			3,864			1,596			(38	)		1,283			1,315
INCOME TAX EXPENSE		850		1,374			1,372			1,748			692			866			876			590

NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES	$	1,735	$	1,975		$	1,600		$	2,116		$	904		$	(904	)	$	407		$	725
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, NET OF TAX		–		–			–			(196	)		–			–			–			–
NET INCOME (LOSS)²	$	1,735	$	1,975		$	1,600		$	1,920		$	904		$	(904	)	$	407		$	725

NET INCOME (LOSS) PER SHARE BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
– BASIC	$	1.63	$	2.02	³	$	1.51		$	1.99		$	0.85		$	(0.85	)	$	0.39		$	0.68
– DILUTED	$	1.63	$	2.02	³	$	1.50		$	1.99		$	0.85		$	(0.85	)	$	0.39		$	0.68

NET INCOME (LOSS) PER SHARE
– BASIC	$	1.63	$	2.02	³	$	1.51		$	1.81		$	0.85		$	(0.85	)	$	0.39		$	0.68
– DILUTED	$	1.63	$	2.02	³	$	1.50		$	1.81		$	0.85		$	(0.85	)	$	0.39		$	0.68

DIVIDENDS PAID PER SHARE	$	0.73	$	0.73		$	0.70		$	0.70		$	0.70		$	0.70		$	0.70		$	0.70
COMMON STOCK PRICE RANGE – HIGH	$	86.99	$	74.56		$	76.23		$	70.40		$	75.43		$	88.93		$	91.04		$	91.60
– LOW	$	71.14	$	70.05		$	62.13		$	61.31		$	65.41		$	65.64		$	83.55		$	80.80

¹ Includes consumer excise taxes:	$	1,825	$	1,814		$	1,765		$	1,691		$	1,785		$	1,782		$	1,751		$	1,688
² Net benefits (charges) for special items included in “Net Income (Loss)”:	$	89	$	14		$	(117	)	$	(39	)	$	(161	)	$	(2,141	)	$	(826	)	$	(206	)


Millions of dollars, except per-share amounts	2003			2002		2001			2000		1999

COMBINED STATEMENT OF INCOME DATA REVENUES AND OTHER INCOME Total sales and other operating revenues	$	120,032		$	98,691	$	104,409		$	117,095	$	84,004
Income from equity affiliates and other income		1,729			222		1,836			2,035		1,709

TOTAL REVENUES AND OTHER INCOME		121,761			98,913		106,245			119,130		85,713
TOTAL COSTS AND OTHER DEDUCTIONS		108,991			94,757		97,954			105,081		79,901

INCOME BEFORE INCOME TAXES		12,770			4,156		8,291			14,049		5,812
INCOME TAX EXPENSE		5,344			3,024		4,360			6,322		2,565

NET INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES		7,426			1,132		3,931			7,727		3,247
Extraordinary loss, net of tax		–			–		(643	)		–		–
Cumulative effect of changes in accounting principles		(196	)		–		–			–		–

NET INCOME	$	7,230		$	1,132	$	3,288		$	7,727	$	3,247

PER-SHARE AMOUNTS
BASIC:
NET INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES¹	$	7.15		$	1.07	$	3.71		$	7.23	$	3.01
Extraordinary item	$	–		$	–	$	(0.61	)	$	–	$	–
Cumulative effect of changes in accounting principles	$	(0.18	)	$	–	$	–		$	–	$	–
NET INCOME¹	$	6.97		$	1.07	$	3.10		$	7.23	$	3.01
DILUTED:
NET INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES¹	$	7.14		$	1.07	$	3.70		$	7.21	$	3.00
Extraordinary item	$	–		$	–	$	(0.61	)	$	–	$	–
Cumulative effect of changes in accounting principles	$	(0.18	)	$	–	$	–		$	–	$	–
NET INCOME¹	$	6.96		$	1.07	$	3.09		$	7.21	$	3.00

CASH DIVIDENDS PER SHARE ²	$	2.86		$	2.80	$	2.65		$	2.60	$	2.48

COMBINED BALANCE SHEET DATA (AT DECEMBER 31)
Current assets	$	19,426		$	17,776	$	18,327		$	17,913	$	17,043
Noncurrent assets		62,044			59,583		59,245			59,708		58,337

TOTAL ASSETS		81,470			77,359		77,572			77,621		75,380

Short-term debt		1,703			5,358		8,429			3,094		6,063
Other current liabilities		14,408			14,518		12,225			13,567		11,620
Long-term debt and capital lease obligations		10,894			10,911		8,989			12,821		13,145
Other noncurrent liabilities		18,170			14,968		13,971			14,770		14,761

TOTAL LIABILITIES		45,175			45,755		43,614			44,252		45,589

STOCKHOLDERS’ EQUITY	$	36,295		$	31,604	$	33,958		$	33,369	$	29,791

TABLE I – COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS AND DEVELOPMENT¹


	Consolidated Companies										Affiliated Companies
Millions of dollars	U.S.		Africa		Asia-Pacific		Other		Total		TCO²		Hamaca		Worldwide
YEAR ENDED DECEMBER 31, 2003
Exploration
Wells	$	424	$	116	$	45	$	72	$	657	$	–	$	–	$	657
Geological and geophysical		39		75		14		30		158		–		–		158
Rentals and other		44		12		58		46		160		–		–		160

Total exploration		507		203		117		148		975		–		–		975

Property acquisitions
Proved³		18		–		20		7		45		–		–		45
Unproved		33		51		6		14		104		–		–		104

Total property acquisitions		51		51		26		21		149		–		–		149

Development		1,048		974		968		461		3,451		551		199		4,201

TOTAL COSTS INCURRED	$	1,606	$	1,228	$	1,111	$	630	$	4,575	$	551	$	199	$	5,325

YEAR ENDED DECEMBER 31, 2002
Exploration
Wells	$	477	$	131	$	48	$	92	$	748	$	–	$	–	$	748
Geological and geophysical		95		69		43		53		260		–		–		260
Rentals and other		35		29		38		43		145		–		–		145

Total exploration		607		229		129		188		1,153		–		–		1,153

Property acquisitions
Proved³		106		–		–		–		106		–		–		106
Unproved		51		6		2		1		60		–		–		60

Total property acquisitions		157		6		2		1		166		–		–		166

Development		1,091		661		1,017		926		3,695		447		353		4,495

TOTAL COSTS INCURRED	$	1,855	$	896	$	1,148	$	1,115	$	5,014	$	447	$	353	$	5,814

YEAR ENDED DECEMBER 31, 2001
Exploration
Wells	$	620	$	172	$	186	$	197	$	1,175	$	–	$	–	$	1,175
Geological and geophysical		46		35		42		65		188		–		–		188
Rentals and other		65		48		15		98		226		–		–		226

Total exploration		731		255		243		360		1,589		–		–		1,589

Property acquisitions
Proved³		25		4		–		–		29		362		–		391
Unproved		50		38		12		–		100		108		–		208

Total property acquisitions		75		42		12		–		129		470		–		599

Development		1,754		551		1,168		494		3,967		266		275		4,508

TOTAL COSTS INCURRED	$	2,560	$	848	$	1,423	$	854	$	5,685	$	736	$	275	$	6,696

TABLE II – CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES¹


	Consolidated Companies										Affiliated Companies
Millions of dollars	U.S.		Africa		Asia-Pacific		Other		Total		TCO		Hamaca		Worldwide

AT DECEMBER 31, 2003
Unproved properties	$	1,316	$	290	$	214	$	1,048	$	2,868	$	108	$	–	$	2,976
Proved properties and related producing assets		37,603		6,474		10,391		10,469		64,937		2,091		356		67,384
Support equipment		677		519		2,110		374		3,680		425		–		4,105
Deferred exploratory wells		248		221		69		120		658		–		–		658
Other uncompleted projects		387		1,906		2,217		334		4,844		1,011		661		6,516
ARO asset²		335		207		83		236		861		20		1		882

GROSS CAPITALIZED COSTS		40,566		9,617		15,084		12,581		77,848		3,655		1,018		82,521

Unproved properties valuation		912		101		60		310		1,383		12		–		1,395
Proved producing properties – depreciation and depletion		27,817		3,656		5,534		5,868		42,875		354		24		43,253
Support equipment depreciation		454		237		1,133		347		2,171		160		–		2,331
ARO asset depreciation²		288		133		55		148		624		4		–		628

Accumulated provisions		29,471		4,127		6,782		6,673		47,053		530		24		47,607

NET CAPITALIZED COSTS	$	11,095	$	5,490	$	8,302	$	5,908	$	30,795	$	3,125	$	994	$	34,914

AT DECEMBER 31, 2002
Unproved properties	$	1,362	$	330	$	259	$	1,134	$	3,085	$	108	$	–	$	3,193
Proved properties and related producing assets		37,441		6,037		10,794		10,185		64,457		1,975		147		66,579
Support equipment		774		447		2,188		377		3,786		338		–		4,124
Deferred exploratory wells		106		130		103		111		450		–		–		450
Other uncompleted projects		502		1,417		1,653		259		3,831		676		693		5,200

GROSS CAPITALIZED COSTS		40,185		8,361		14,997		12,066		75,609		3,097		840		79,546

Unproved properties valuation		961		80		90		277		1,408		9		–		1,417
Proved producing properties – depreciation and depletion		27,115		3,275		5,470		5,358		41,218		285		9		41,512
Future abandonment and restoration		999		508		304		392		2,203		24		–		2,227
Support equipment depreciation		557		289		1,145		223		2,214		138		–		2,352

Accumulated provisions		29,632		4,152		7,009		6,250		47,043		456		9		47,508

NET CAPITALIZED COSTS	$	10,553	$	4,209	$	7,988	$	5,816	$	28,566	$	2,641	$	831	$	32,038

AT DECEMBER 31, 2001
Unproved properties	$	1,178	$	304	$	565	$	1,168	$	3,215	$	108	$	–	$	3,323
Proved properties and related producing assets		35,665		5,531		10,590		9,253		61,039		1,878		91		63,008
Support equipment		766		390		2,177		313		3,646		293		–		3,939
Deferred exploratory wells		91		390		128		79		688		–		–		688
Other uncompleted projects		1,080		753		686		292		2,811		245		381		3,437

GROSS CAPITALIZED COSTS		38,780		7,368		14,146		11,105		71,399		2,524		472		74,395

Unproved properties valuation		807		86		73		222		1,188		7		–		1,195
Proved producing properties – depreciation and depletion		25,844		3,020		4,802		4,736		38,402		212		3		38,617
Future abandonment and restoration		1,016		449		281		342		2,088		19		–		2,107
Support equipment depreciation		452		160		1,122		162		1,896		123		–		2,019

Accumulated provisions		28,119		3,715		6,278		5,462		43,574		361		3		43,938

NET CAPITALIZED COSTS	$	10,661	$	3,653	$	7,868	$	5,643	$	27,825	$	2,163	$	469	$	30,457


	Consolidated Companies															Affiliated Companies
Millions of dollars	U.S.			Africa			Asia-Pacific			Other			Total			TCO			Hamaca			Worldwide
YEAR ENDED DECEMBER 31, 2003
Revenues from net production
Sales	$	4,507		$	1,339		$	1,497		$	2,556		$	9,899		$	1,116		$	104		$	11,119
Transfers		4,921			1,835			3,304			1,356			11,416			—			—			11,416

Total		9,428			3,174			4,801			3,912			21,315			1,116			104			22,535
Production expenses excluding taxes		(1,959	)		(505	)		(783	)		(669	)		(3,916	)		(117	)		(20	)		(4,053	)
Taxes other than on income		(356	)		(22	)		(127	)		(100	)		(605	)		(29	)		—			(634	)
Proved producing properties:
depreciation and depletion		(1,532	)		(327	)		(712	)		(846	)		(3,417	)		(97	)		(4	)		(3,518	)
Accretion expense²		(69	)		(20	)		(13	)		(26	)		(128	)		(2	)		—			(130	)
Exploration expenses		(193	)		(123	)		(138	)		(117	)		(571	)		—			—			(571	)
Unproved properties valuation		(20	)		(20	)		(9	)		(41	)		(90	)		—			—			(90	)
Other (expense) income³		(173	)		(173	)		(504	)		(175	)		(1,025	)		(4	)		(35	)		(1,064	)

Results before income taxes		5,126			1,984			2,515			1,938			11,563			867			45			12,475
Income tax expense		(1,890	)		(1,410	)		(1,447	)		(831	)		(5,578	)		(260	)		—			(5,838	)

RESULTS OF PRODUCING OPERATIONS	$	3,236		$	574		$	1,068		$	1,107		$	5,985		$	607		$	45		$	6,637

YEAR ENDED DECEMBER 31, 2002⁴
Revenues from net production
Sales	$	2,737		$	1,121		$	1,410		$	2,080		$	7,348		$	955		$	44		$	8,347
Transfers		4,425			1,663			3,090			1,202			10,380			—			—			10,380

Total		7,162			2,784			4,500			3,282			17,728			955			44			18,727
Production expenses excluding taxes		(1,982	)		(415	)		(844	)		(606	)		(3,847	)		(130	)		(4	)		(3,981	)
Taxes other than on income		(339	)		(24	)		(114	)		(77	)		(554	)		(36	)		—			(590	)
Proved producing properties:
depreciation and depletion		(1,483	)		(314	)		(660	)		(654	)		(3,111	)		(86	)		(5	)		(3,202	)
FAS 19 abandonment provision²		(94	)		(38	)		(13	)		(40	)		(185	)		(5	)		—			(190	)
Exploration expenses		(216	)		(106	)		(109	)		(160	)		(591	)		—			—			(591	)
Unproved properties valuation		(35	)		(14	)		(9	)		(67	)		(125	)		—			—			(125	)
Other (expense) income³		(359	)		(179	)		(399	)		59			(878	)		(5	)		(12	)		(895	)

Results before income taxes		2,654			1,694			2,352			1,737			8,437			693			23			9,153
Income tax expense		(933	)		(1,202	)		(1,434	)		(677	)		(4,246	)		(208	)		—			(4,454	)

RESULTS OF PRODUCING OPERATIONS	$	1,721		$	492		$	918		$	1,060		$	4,191		$	485		$	23		$	4,699

YEAR ENDED DECEMBER 31, 2001⁴
Revenues from net production
Sales	$	6,557		$	1,147		$	1,264		$	2,181		$	11,149		$	673		$	6		$	11,828
Transfers		2,458			1,913			2,796			1,107			8,274			—			—			8,274

Total		9,015			3,060			4,060			3,288			19,423			673			6			20,102
Production expenses excluding taxes		(2,047	)		(425	)		(804	)		(664	)		(3,940	)		(114	)		(6	)		(4,060	)
Taxes other than on income		(395	)		(22	)		(52	)		(23	)		(492	)		(28	)		—			(520	)
Proved producing properties: depreciation, depletion and abandonment provision		(1,614	)		(344	)		(498	)		(658	)		(3,114	)		(80	)		(1	)		(3,195	)
Exploration expenses		(424	)		(132	)		(234	)		(298	)		(1,088	)		—			—			(1,088	)
Unproved properties valuation		(38	)		(33	)		(9	)		(77	)		(157	)		—			—			(157	)
Other (expense) income³		(1,653	)		(110	)		(209	)		(5	)		(1,977	)		9			2			(1,966	)

Results before income taxes		2,844			1,994			2,254			1,563			8,655			460			1			9,116
Income tax expense		(1,074	)		(1,455	)		(1,432	)		(620	)		(4,581	)		(138	)		—			(4,719	)

RESULTS OF PRODUCING OPERATIONS	$	1,770		$	539		$	822		$	943		$	4,074		$	322		$	1		$	4,397

TABLE IV – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES – UNIT PRICES AND COSTS^1,2


	Consolidated Companies										Affiliated Companies
	U.S.		Africa		Asia-Pacific		Other		Total		TCO		Hamaca		Worldwide

YEAR ENDED DECEMBER 31, 2003
Average sales prices
Liquids, per barrel	$	26.66	$	28.54	$	24.83	$	27.56	$	26.69	$	22.07	$	17.06	$	26.24
Natural gas, per thousand cubic feet		5.01		0.04		3.51		2.58		4.08		0.68		0.33		3.96
Average production costs, per barrel		5.82		4.42		3.93		3.99		4.79		2.04		3.24		4.60

YEAR ENDED DECEMBER 31, 2002
Average sales prices
Liquids, per barrel	$	21.34	$	24.33	$	21.76	$	23.31	$	22.36	$	18.16	$	18.91	$	22.03
Natural gas, per thousand cubic feet		2.89		0.04		2.67		2.11		2.62		0.57		–		2.55
Average production costs, per barrel³		5.48		3.49		3.88		3.59		4.44		2.19		1.58		4.29

YEAR ENDED DECEMBER 31, 2001
Average sales prices
Liquids, per barrel	$	21.33	$	23.70	$	20.11	$	22.59	$	21.68	$	13.31	$	12.45	$	21.08
Natural gas, per thousand cubic feet		4.38		0.04		3.04		2.51		3.78		0.47		–		3.69
Average production costs, per barrel³		5.32		3.23		3.94		4.03		4.45		2.04		13.09		4.31

TABLE V – RESERVE QUANTITY INFORMATION

The company’s estimated net proved underground oil and gas reserves and changes thereto for the years 2003, 2002 and 2001 are shown in the following table. Proved reserves are estimated by company asset teams composed of earth scientists and reservoir engineers. These proved reserve estimates are reviewed annually by the company’s Reserves Advisory Committee to ensure that rigorous professional standards and the reserves definitions prescribed by the U.S. Securities and Exchange Commission are consistently applied throughout the company.

Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change as additional information becomes available.


NET PROVED RESERVES OF CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS																									NET PROVED RESERVES OF NATURAL GAS

	Millions of barrels																								Billions of cubic feet
	Consolidated Companies															Affiliates									Consolidated Companies															Affiliates
							Asia-															World-									Asia-															World-
	U.S.			Africa			Pacific			Other			Total			TCO			Hamaca			wide			U.S.			Africa			Pacific			Other			Total			TCO			Hamaca			wide

RESERVES AT JANUARY 1, 2001		2,614			1,505			1,894			822			6,835			1,310			374			8,519			7,923			772			4,442			2,991			16,128			1,683			33			17,844
Changes attributable to:
Revisions		(225	)		45			135			(60	)		(105	)		46			(2	)		(61	)		(20	)		780			330			(10	)		1,080			317			–			1,397
Improved recovery		79			35			47			51			212			–			–			212			24			7			11			16			58			–			–			58
Extensions and discoveries		67			88			34			40			229			88			115			432			587			329			164			445			1,525			130			9			1,664
Purchases¹		1			–			–			–			1			146			–			147			41			–			6			6			53			187			–			240
Sales²		(11	)		–			–			–			(11	)		–			–			(11	)		(180	)		–			–			–			(180	)		–			–			(180	)
Production		(224	)		(129	)		(204	)		(108	)		(665	)		(49	)		–			(714	)		(988	)		(16	)		(194	)		(360	)		(1,558	)		(55	)		–			(1,613	)

RESERVES AT DECEMBER 31, 2001		2,301			1,544			1,906			745			6,496			1,541			487			8,524			7,387			1,872			4,759			3,088			17,106			2,262			42			19,410
Changes attributable to:
Revisions		(116	)		164			(114	)		17			(49	)		199			–			150			(598	)		277			390			92			161			293			1			455
Improved recovery		99			82			22			36			239			–			–			239			21			42			4			10			77			–			–			77
Extensions and discoveries		48			301			85			8			442			–			–			442			395			134			260			103			892			–			–			892
Purchases¹		8			–			–			–			8			–			–			8			93			–			8			–			101			–			–			101
Sales²		(3	)		–			–			–			(3	)		–			–			(3	)		(3	)		–			–			–			(3	)		–			–			(3	)
Production		(220	)		(115	)		(195	)		(109	)		(639	)		(51	)		(2	)		(692	)		(878	)		(27	)		(257	)		(369	)		(1,531	)		(66	)		–			(1,597	)

RESERVES AT DECEMBER 31, 2002		2,117			1,976			1,704			697			6,494			1,689			485			8,668			6,417			2,298			5,164			2,924			16,803			2,489			43			19,335
Changes attributable to:
Revisions		(9	)		(1	)		48			19			57			200			–			257			(606	)		342			915			976			1,627			109			70			1,806
Improved recovery		53			36			54			52			195			–			–			195			23			17			15			35			90			–			–			90
Extensions and discoveries		124			24			18			26			192			–			–			192			388			3			88			47			526			–			–			526
Purchases¹		1			–			–			12			13			–			–			13			8			–			7			55			70			–			–			70
Sales²		(23	)		–			(42	)		(1	)		(66	)		–			–			(66	)		(64	)		–			–			(6	)		(70	)		–			–			(70	)
Production		(205	)		(112	)		(179	)		(109	)		(605	)		(49	)		(6	)		(660	)		(813	)		(18	)		(296	)		(366	)		(1,493	)		(72	)		(1	)		(1,566	)

RESERVES AT DECEMBER 31, 2003		2,058			1,923			1,603			696			6,280			1,840			479			8,599			5,353			2,642			5,893			3,665			17,553			2,526			112			20,191

DEVELOPED RESERVES

At January 1, 2001		2,083			976			1,276			538			4,873			795			–			5,668			6,408			294			3,108			2,347			12,157			1,019			–			13,176
At December 31, 2001		1,887			923			1,491			517			4,818			1,007			38			5,863			6,246			444			3,170			2,231			12,091			1,477			6			13,574
At December 31, 2002		1,766			1,042			1,297			529			4,634			999			63			5,696			5,636			582			3,196			2,157			11,571			1,474			6			13,051
At December 31, 2003		1,651			1,059			1,229			522			4,461			1,304			140			5,905			4,801			954			3,850			3,043			12,648			1,789			52			14,489

¹ Includes reserves acquired through property exchanges.
² Includes reserves disposed of through property exchanges.

TABLE VI – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES

The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FAS No. 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions, and include estimated costs for asset retirement obligations. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related

assets. Discounted future net cash flows are calculated using 10 percent midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced.

The information provided does not represent management’s estimate of the company’s expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under FAS No. 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the company’s future cash flows or value of its oil and gas reserves.


	Consolidated Companies															Affiliated Companies
Millions of dollars	U.S.			Africa			Asia-Pacific			Other			Total			TCO			Hamaca			Worldwide

AT DECEMBER 31, 2003
Future cash inflows from production	$	87,079		$	55,532		$	59,319		$	29,987		$	231,917		$	56,485		$	9,018		$	297,420
Future production costs		(25,049	)		(8,237	)		(17,776	)		(6,334	)		(57,396	)		(6,099	)		(1,878	)		(65,373	)
Future development costs		(4,208	)		(4,524	)		(4,161	)		(1,971	)		(14,864	)		(6,066	)		(463	)		(21,393	)
Future income taxes		(19,567	)		(25,369	)		(15,925	)		(7,888	)		(68,749	)		(12,520	)		(2,270	)		(83,539	)

Undiscounted future net cash flows		38,255			17,402			21,457			13,794			90,908			31,800			4,407			127,115
10 percent midyear annual discount for timing of estimated cash flows		(17,177	)		(8,482	)		(9,405	)		(5,039	)		(40,103	)		(20,140	)		(2,949	)		(63,192	)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS	$	21,078		$	8,920		$	12,052		$	8,755		$	50,805		$	11,660		$	1,458		$	63,923

AT DECEMBER 31, 2002*
Future cash inflows from production	$	77,912		$	52,513		$	59,550		$	26,531		$	216,506		$	52,457		$	9,777		$	278,740
Future production costs		(26,315	)		(6,435	)		(14,086	)		(5,970	)		(52,806	)		(4,959	)		(1,730	)		(59,495	)
Future development costs		(3,633	)		(3,454	)		(4,505	)		(1,868	)		(13,460	)		(5,377	)		(578	)		(19,415	)
Future income taxes		(16,231	)		(25,060	)		(17,781	)		(6,797	)		(65,869	)		(11,899	)		(2,540	)		(80,308	)

Undiscounted future net cash flows		31,733			17,564			23,178			11,896			84,371			30,222			4,929			119,522
10 percent midyear annual discount for timing of estimated cash flows		(13,872	)		(8,252	)		(9,971	)		(3,691	)		(35,786	)		(18,964	)		(3,581	)		(58,331	)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS	$	17,861		$	9,312		$	13,207		$	8,205		$	48,585		$	11,258		$	1,348		$	61,191

AT DECEMBER 31, 2001
Future cash inflows from production	$	54,238		$	28,019		$	43,389		$	20,432		$	146,078		$	29,433		$	5,922		$	181,433
Future production costs		(25,851	)		(6,640	)		(16,131	)		(6,381	)		(55,003	)		(4,325	)		(584	)		(59,912	)
Future development costs		(5,020	)		(3,466	)		(4,714	)		(2,492	)		(15,692	)		(4,540	)		(509	)		(20,741	)
Future income taxes		(7,981	)		(10,476	)		(9,858	)		(4,370	)		(32,685	)		(5,805	)		(1,642	)		(40,132	)

Undiscounted future net cash flows		15,386			7,437			12,686			7,189			42,698			14,763			3,187			60,648
10 percent midyear annual discount for timing of estimated cash flows		(6,882	)		(3,609	)		(5,857	)		(2,602	)		(18,950	)		(9,121	)		(2,433	)		(30,504	)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS	$	8,504		$	3,828		$	6,829		$	4,587		$	23,748		$	5,642		$	754		$	30,144

TABLE VII – CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES


	Consolidated Companies									Affiliated Companies									Worldwide
Millions of dollars	2003			2002			2001			2003			2002			2001			2003			2002			2001

PRESENT VALUE AT JANUARY 1	$	48,585		$	23,748		$	59,802		$	12,606		$	6,396		$	6,186		$	61,191		$	30,144		$	65,988
Sales and transfers of oil and gas produced net of production costs		(16,794	)		(13,327	)		(15,161	)		(1,054	)		(829	)		(531	)		(17,848	)		(14,156	)		(15,692	)
Development costs incurred		3,451			3,695			3,967			750			800			541			4,201			4,495			4,508
Purchases of reserves		97			181			40			–			–			778			97			181			818
Sales of reserves		(839	)		(42	)		(366	)		–			–			–			(839	)		(42	)		(366	)
Extensions, discoveries and improved recovery less related costs		5,445			7,472			2,747			–			–			484			5,445			7,472			3,231
Revisions of previous quantity estimates		1,168			104			524			652			917			400			1,820			1,021			924
Net changes in prices, development and production costs		2,054			41,044			(59,995	)		(1,187	)		6,722			(2,457	)		867			47,766			(62,452	)
Accretion of discount		7,903			3,987			10,144			1,709			895			876			9,612			4,882			11,020
Net change in income tax		(264	)		(18,277	)		22,046			(359	)		(2,295	)		119			(623	)		(20,572	)		22,165

Net change for the year		2,221			24,837			(36,054	)		511			6,210			210			2,732			31,047			(35,844	)

PRESENT VALUE AT DECEMBER 31	$	50,806		$	48,585		$	23,748		$	13,117		$	12,606		$	6,396		$	63,923		$	61,191		$	30,144

On October 9, 2001, the company changed its name from Chevron Corporation to ChevronTexaco Corporation. Filings with the Securities and Exchange Commission prior to that date may be found under the company’s former name.

Copies of above exhibits not contained herein are available to any security holder upon written request to the Secretary’s Department, ChevronTexaco Corporation, 6001 Bollinger Canyon Road, San Ramon, California 94583.


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



										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


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






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

February 25, 2004


¹	Accounted for under the equity method pre-merger and the cost basis post-merger.
²	The company’s share of income and underlying equity in the net assets of its investments includes the effects of write-downs of certain investments – largely related to Dynegy Inc. and Caltex Australia Ltd., as described in the preceding section.
³	2002 conformed to the 2003 presentation.


¹	Refer to Note 25 on page FS-50 for a discussion of the effect on 2003 PP&E balances and depreciation expenses related to the adoption of FAS 143, “Accounting for Asset Retirement Obligations.”
²	Net of accumulated abandonment and restoration costs of $2,263 and $2,155 at December 31, 2002 and 2001, respectively.
³	Net of dry hole expense related to prior years’ expenditures of $124, $36 and $228 in 2003, 2002 and 2001, respectively.
⁴	Primarily coal, real estate assets and management information systems.


^*	Discount rate and expected rate of return on plan assets were updated quarterly for the main U.S. pension plan.

¹		The amount in 2003 includes a benefit of $0.16 for the company’s share of a capital stock transaction of its Dynegy Inc. affiliate, which, under the applicable accounting rules, was recorded directly to retained earnings and not included in net income for the period.
²		Chevron Corporation dividend pre-merger.

¹		Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. See Note 25, FAS 143 “Asset Retirement Obligations,” on page FS-50.
²		Includes acquisition costs for an additional 5 percent interest in 2001.
³		Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired through property exchanges.

¹		Includes assets held for sale.
²		See Note 25, FAS 143 “Asset Retirement Obligations,” on page FS-50.

¹		The value of owned production consumed on lease as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
²		See Note 25 on page FS-50, FAS 143 “Asset Retirement Obligations.”
³		Includes net sulfur income, foreign currency transaction gains and losses, certain significant impairment write-downs, miscellaneous expenses, etc. Also includes net income from related oil and gas activities that do not have oil and gas reserves attributed to them (for example, net income from technical and operating service agreements) and items identified in the Management’s Discussion and Analysis on pages FS-6 and FS-7.
⁴		2002 and 2001 include certain reclassifications to conform to 2003 presentation.

¹		The value of owned production consumed on lease as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
²		Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.
³		Conformed to 2003 presentation to exclude taxes.


Exhibit No.			Description

	3	.1	Restated Certificate of Incorporation of ChevronTexaco Corporation, dated October 9, 2001, filed as Exhibit 3.1 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
	3	.2	By-Laws of ChevronTexaco Corporation, as amended September 26, 2001, filed as Exhibit 3.2 for ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.
			Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the corporation and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Commission upon request.
	10	.1	ChevronTexaco Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, approved by the company’s stockholders on May 22, 2003, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated April 15, 2002, and incorporated herein by reference.
	10	.2	Management Incentive Plan of ChevronTexaco Corporation, as amended effective October 9, 2001, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated April 15, 2002, and incorporated herein by reference.
	10	.3*	ChevronTexaco Corporation Excess Benefit Plan, amended and restated as of April 1, 2002.
	10	.4	ChevronTexaco Corporation Long-Term Incentive Plan, including January 28, 2004 amendments, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated March 26, 2004, and incorporated herein by reference.
	10	.6	ChevronTexaco Corporation Deferred Compensation Plan for Management Employees, as amended and restated effective April 1, 2002, filed as Exhibit 10.1 to ChevronTexaco Corporation’s Report on Form 10-Q for the quarterly period ended March 31, 2002, and incorporated herein by reference.
	10	.8	Texaco Inc. Stock Incentive Plan, adopted May 9, 1989, as amended May 13, 1993, and May 13, 1997, filed as Exhibit 10.13 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
	10	.9	Supplemental Pension Plan of Texaco Inc., dated June 26, 1975, filed as Exhibit 10.14 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
	10	.10	Supplemental Bonus Retirement Plan of Texaco Inc., dated May 1, 1981, filed as Exhibit 10.15 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
	10	.11	Texaco Inc. Director and Employee Deferral Plan approved March 28, 1997, filed as Exhibit 10.16 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
	10	.12	ChevronTexaco Corporation 1998 Stock Option Program for U.S. Dollar Payroll Employees, filed as Exhibit 10.12 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.
	12	.1*	Computation of Ratio of Earnings to Fixed Charges (page E-3).
	21	.1*	Subsidiaries of ChevronTexaco Corporation (page E-4 to E-5).
	23	.1*	Consent of PricewaterhouseCoopers LLP (page E-6).


Exhibit No.			Description

24.1 to 24.16*			Powers of Attorney for directors and certain officers of ChevronTexaco Corporation, authorizing the signing of the Annual Report on Form 10-K on their behalf.
	31	.1*	Rule 13(a)-14(a)/15(d)-14(a) Certification of the company’s Chief Executive Officer (page E-7).
	31	.2*	Rule 13(a)-14(a)/15(d)-14(a) Certification of the company’s Chief Financial Officer (page E-8).
	32	.1*	Section 1350 Certification of the company’s Chief Executive Officer (page E-9).
	32	.2*	Section 1350 Certification of the company’s Chief Financial Officer (page E-10).
	99	.1*	Definitions of Selected Financial Terms (page E-11).