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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549
Form 10-K

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

For the fiscal year ended December 31, 2003

OR

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

For the transition period from                     to                     

Commission File Number 1-368-2

ChevronTexaco Corporation

(Exact name of registrant as specified in its charter)
         

Delaware
 
94-0890210
  6001 Bollinger Canyon Road,
San Ramon, California 94583

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

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

NONE

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

Securities registered pursuant to Section 12(b) of the Act:

     

Title of Each Class
  Name of Each Exchange
on Which Registered

 
Common stock par value $.75 per share
Preferred stock purchase rights
  New York Stock Exchange, Inc.
Pacific Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

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)




TABLE OF CONTENTS

                 
Item Page No.


         PART I        
 1.    Business     3  
           (a) General Development of Business     3  
           (b) Description of Business and Properties     5  
                   Capital and Exploratory Expenditures     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

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CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

      Among the factors that could cause actual results to differ materially are crude oil and natural gas prices; refining margins and marketing margins; chemicals prices and competitive conditions affecting supply and demand for aromatics, olefins and additives products; actions of competitors; the competitiveness of alternate energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; 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.

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PART I

Item 1.     Business

     (a) General Development of Business

Summary Description of ChevronTexaco

ChevronTexaco Corporation,1 a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial and management support to U.S. and foreign subsidiaries that engage in fully integrated petroleum operations, chemicals operations, coal mining, power and energy services. The company 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.

Overview of Petroleum Industry

Petroleum industry operations and profitability are influenced by many factors, over some of which individual petroleum companies have little control. Governmental policies, particularly in the areas of taxation, energy and the environment, have a significant impact on petroleum activities, regulating where and how companies conduct their operations and formulate their products and, in some cases, limiting their profits directly. Prices for crude oil and natural gas, petroleum products and petrochemicals are determined by supply and demand for these commodities. The members of the Organization of Petroleum Exporting Countries (OPEC) are typically the world’s swing producers of crude oil, and their production levels are a major factor in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and worldwide economies, although weather patterns and taxation relative to other energy sources also play a significant part. 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.

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Operating Environment

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 Strategic Direction

ChevronTexaco’s primary objective is to achieve sustained financial returns from its operations that will enable it to outperform its competitors. The company 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.

Supporting these four priorities is a focus on:

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

The Corporate Strategic Plan builds on this framework with strategies focused on appropriately balancing financial returns and growth. 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.

Texaco Merger Transaction

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

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     (b)  Description of Business and Properties

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.

Capital and Exploratory Expenditures

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.

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Petroleum — Exploration and Production

Liquids and Natural Gas Production

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.

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

                                                   
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 Affiliates6, 7
    1,808       1,897       4,292       4,376       2,523       2,626  
     
     
     
     
     
     
 

  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.

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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.

Acreage

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.

Acreage1 At December 31, 2003

(Thousands of Acres)
                                                 
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  
     
     
     
     
     
     
 

  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.

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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.

Productive Oil and Gas Wells at December 31, 2003

                                 
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  

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

Reserves and Contract Obligations

Table V on 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.

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Reserves Replacement — 2003

                                                 
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 %
     
     
     
     
                 

  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.

Development Activities

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.

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Development Well Activity

                                                                 
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  
     
     
     
     
     
     
     
     
 

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

Exploration Activities

The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the last three years and the number of exploratory wells drilling at December 31, 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.

Exploratory Well Activity

                                                                 
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  
     
     
     
     
     
     
     
     
 

  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.

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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.

Review of Ongoing Exploration and Production Activities in Key Areas

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.

Consolidated Operations

a) United States

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

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with an API gravity lower than 22 degrees). Heat management continued to be a major focus for the oil assets, enabling greater recovery of this resource.

   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.

b) Africa

   Nigeria: ChevronTexaco’s principal subsidiary in Nigeria, Chevron Nigeria Limited (CNL), operates and holds a 40 percent interest in 11 concessions, predominantly in the 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.

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   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.

c) Asia-Pacific

   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

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cogeneration facility in support of CPI’s operation in North Duri. In addition to the above interests, ChevronTexaco has a 25 percent nonoperated interest in South Natuna Sea Block B.

ChevronTexaco’s share of net production during 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.

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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.

d) Other International Areas

   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

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barrels of oil-equivalent production per day — and midstream assets in western Canada. This decision does not affect strategically significant assets in Canada, including the Athabasca Oil Sands Project, MacKenzie Delta gas and east coast Canada exploration, development and production activities.

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.

e) Affiliate Operations

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.

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Petroleum — Natural Gas and Natural Gas Liquids

The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. 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.

Petroleum — Refining

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.

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

Petroleum Refineries: Locations, Capacities and Inputs

(Inputs and Capacities in Thousands of Barrels per Day)
                                             
December 31, 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  
     
     
     
     
     
 

  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.

Petroleum — Refined Products Marketing

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

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

Refined Products Sales Volumes1

(Thousands of Barrels per Day)
                           
2003 2002 2001



United States
                       
 
Gasolines
    669       680       709  
 
Jet Fuel
    314       352       424  
 
Gas Oils and Kerosene
    196       259       245  
 
Residual Fuel Oil
    202       177       183  
 
Other Petroleum Products2
    133       132       122  
     
     
     
 
 
Total United States
    1,514       1,600       1,683  
     
     
     
 
International
                       
 
Gasolines
    543       519       533  
 
Jet Fuel
    186       164       185  
 
Gas Oils and Kerosene
    623       619       702  
 
Residual Fuel Oil
    324       329       503  
 
Other Petroleum Products2
    47       57       75  
 
Share of Affiliates’ Sales
    501       487       456  
     
     
     
 
 
Total International
    2,224       2,175       2,454  
     
     
     
 
Total Worldwide
    3,738       3,775       4,137  
     
     
     
 

  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.

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Petroleum — Transportation

   Pipelines: ChevronTexaco owns and operates an extensive system of crude oil, refined products, chemicals, natural gas liquids and natural gas pipelines in the United States. The company also has direct or indirect interests in other U.S. and international pipelines. The company’s ownership interests in pipelines are summarized in the following table:

Pipeline Mileage at December 31, 2003

           
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  
     
 

  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.

Controlled Tankers at December 31, 2003

                                   
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  
     
     
     
     
 

  Greater than one year.

Federal law requires that cargo transported between U.S. ports be carried in ships built and registered in the United States, owned and operated by U.S. entities, and manned by U.S. crews. At year-end 2003, the company’s U.S. flag fleet was engaged primarily in transporting refined products between the Gulf Coast

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and the East Coast, and from California refineries to terminals on the West Coast and in Alaska and Hawaii.

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

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.

Chemicals

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

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.

Coal

The company’s coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), owned and operated two surface mines and one underground mine at year-end 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.

Other Activities — Synthetic Crude Oil

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

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started processing bitumen from Train 1 of the Muskeg River Mine. Full operation with both processing trains began in June. Bitumen production in the fourth quarter of 2003 averaged approximately 130,000 barrels per day. Full capacity is expected to reach 155,000 barrels per day.

Global Power Generation

ChevronTexaco’s Global Power Generation (GPG) has more than 20 years’ experience in developing and operating commercial power projects. With 13 power assets located in the United States, 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.

Worldwide Gasification Technology

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.

Gas-to-Liquids

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

Research and Technology

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

Additionally, ChevronTexaco’s Technology Ventures Company focuses 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.

Environmental Protection

Virtually all aspects of the company’s businesses are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to change and increase in both number and complexity and to govern not only the manner in which the company conducts its operations, but also the products it sells. ChevronTexaco expects more environmental-related

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regulations in the countries where it has operations. Most of the costs of complying with the many laws and regulations pertaining to its operations are embedded in the normal costs of conducting its business.

In 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.

Web Site Access to SEC Reports

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

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

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

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Item 2.     Properties

The location and character of the company’s oil, natural gas and coal properties and its refining, marketing, transportation and chemicals facilities are described above under Item 1. Business. Information required by the Securities Exchange Act Industry Guide No. 2 (“Disclosure of Oil and Gas Operations”) is also contained in Item 1 and in Tables I through VII on pages FS-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.

Item 3.     Legal Proceedings

Richmond Refinery — Alleged Air Violations

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.

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

None.

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Executive Officers of the Registrant at March 1, 2004

             
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

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

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

PART II

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

The information on ChevronTexaco’s common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-51 of this Annual Report on Form 10-K.

 
Item 6. Selected Financial Data

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

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

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

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

 
Item 8. Financial Statements and Supplementary Data

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

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

None.

Item 9A.     Controls and Procedures

      (a) Evaluation of Disclosure Controls and Procedures

        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.

      (b) Changes in Internal Control Over Financial Reporting

        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.

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PART III

Item 10.     Directors and Executive Officers of the Registrant

The information on Directors appearing under the heading “Election of Directors — Nominees For Directors” in the Notice of the 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/.

Item 11.     Executive Compensation

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.

Item 12.     Security Ownership of Certain Beneficial Owners and Management

The information appearing under the headings “Stock Ownership Information — Directors’ and Executive Officers’ Stock Ownership” and “Stock Ownership Information — Other Security Holders” in the Notice of the 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.

Item 13.     Certain Relationships and Related Transactions

The information appearing under the heading “Board Operations — Certain Business Relationships Between ChevronTexaco and its Directors and Officers” in the Notice of the 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.

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Item 14.     Principal Auditor Fees and Services

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.

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PART IV

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

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

(1) Financial Statements:
         
Page(s)

Report of Independent 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  

      (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.

   (b) Reports on Form 8-K:

  (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.

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SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Millions of Dollars
                         
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
  $     $     $  
     
     
     
 

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 9th day of March, 2004.

  ChevronTexaco Corporation

  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.

     
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
   

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

     
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

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

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.


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Table of Contents

     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.



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Table of Contents

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

     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

   
(BAR CHART)
 
 
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
     
     
     


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Table of Contents

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


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

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

     

     

     



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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


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

(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,


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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
     
(GRAPH)
 
  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.

 

 
 



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     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 Transportation2,4
                       
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

     

     



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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
      
      
      
      


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

(GRAPH)  
 
  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.
 


Capital and Exploratory Expenditures

                                                                         
                    2003                     2002                     2001  
Millions of dollars   U.S.     Int'l.     Total     U.S.     Int'l.     Total     U.S.     Int'l.     Total  
 
Exploration and Production
  $ 1,641     $ 4,034     $ 5,675     $ 1,888     $ 4,395     $ 6,283     $ 2,420     $ 4,709     $ 7,129  
Refining, Marketing and Transportation
    403       697       1,100       750       882       1,632       873       1,271       2,144  
Chemicals
    173       24       197       272       37       309       145       34       179  
All Other
    371       20       391       855 *     176 *     1,031       2,570       6       2,576  
 
Total
  $ 2,588     $ 4,775     $ 7,363     $ 3,765     $ 5,490     $ 9,255     $ 6,008     $ 6,020     $ 12,028  
 
Total, Excluding Equity in Affiliates
  $ 2,306     $ 3,920     $ 6,226     $ 3,312     $ 4,590     $ 7,902     $ 4,934     $ 5,382     $ 10,316  
 
* 2002 conformed to the 2003 presentation.

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     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
       
(BAR GRAPH)  
 
  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


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

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.


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     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 Debt1,2
    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


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

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.
(BAR GRAPH)  
 
  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


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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.


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

     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.


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     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


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

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.
     
     
     
     
     
     
     
     


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REPORT OF MANAGEMENT

To the Stockholders of ChevronTexaco Corporation

Management of ChevronTexaco is responsible for preparing the accompanying financial statements and for ensuring their integrity and objectivity. The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgments.
     The company’s statements have been audited by PricewaterhouseCoopers LLP, independent auditors selected by the Audit Committee and approved by the stockholders. Management has made available to PricewaterhouseCoopers LLP all the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.
     Management of the company has established and maintains a system of internal accounting controls that is designed to provide reasonable assurance that assets are safeguarded, transactions are properly recorded and executed in accordance with management’s authorization, and the books and records accurately reflect the disposition of assets. The system of internal controls includes appropriate division of responsibility. The company maintains an internal audit department that conducts an extensive program of internal audits and independently assesses the effectiveness of the internal controls.
     The Audit Committee is composed of directors who are not officers or employees of the company. It meets regularly with members of management, the internal auditors and the independent auditors to discuss the adequacy of the company’s internal controls, its financial statements, and the nature, extent and results of the audit effort. Both the internal and the independent auditors have free and direct access to the Audit Committee without the presence of management.
         
 
       
 
       
 
       
 
       
/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
       
 
       
 
       

 
       

REPORT OF INDEPENDENT AUDITORS

To the Stockholders and the Board of Directors of ChevronTexaco Corporation

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.
 
As discussed in Note 25 on page FS-50 to the financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003.
 
 

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

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Consolidated Statement of Income
Millions of dollars, except per-share amounts
                         
    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  
See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statement of Comprehensive Income
Millions of dollars
                         
    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  
 
See accompanying Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet
Millions of dollars, except per-share amounts
                 
    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  
 
See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statement of Cash Flows
Millions of dollars
                         
    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  
 
See accompanying Notes to Consolidated Financial Statements.

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Table of Contents

   
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Consolidated Statement of Stockholders’ Equity
Shares in thousands; amounts in millions of dollars
                                                 
            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  
 
 See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statement of Stockholders’ Equity – Continued
Shares in thousands; amounts in millions of dollars
                                                 
            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  
 
 See accompanying Notes to Consolidated Financial Statements.

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

NOTE 1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General ChevronTexaco manages its investments in and provides administrative, financial and management support to U.S. and foreign subsidiaries and affiliates that engage in fully integrated petroleum 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-


FS-28


Table of Contents

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:

 



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»
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.


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Table of Contents

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.

 

 



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»
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  


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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.
     
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.


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»
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


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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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



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»
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)


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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.

     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. 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.



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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.

 
 



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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 Share2,3
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  
 
   
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.

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

NOTE 15.
PROPERTIES, PLANT AND EQUIPMENT1

                                                                                                 
    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  
 
   
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.

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 %
 


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Table of Contents

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.


FS-41


Table of Contents

 
   
»
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.
     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.

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

 



FS-42


Table of Contents

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.

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

NOTE 21. EMPLOYEE BENEFIT PLANS – Continued

     The accumulated benefit obligations for all U.S. pension plans and pension plans outside the U.S. were $5,374 and $2,372, respectively, at December 31, 2003, and $4,945 and $1,740, respectively, at December 31, 2002.

     Information for pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2003 and 2002 was:
                 
    At December 31
    2003     2002  
 
Projected benefit obligations
  $ 6,637     $ 5,761  
Accumulated benefit obligations
    6,067       5,327  
Fair value of plan assets
    4,791       3,283  
 


     The components of net periodic benefit cost for 2003, 2002 and 2001 were:
                                                                         
    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 %
 
   
*
Discount rate and expected rate of return on plan assets were updated quarterly for the main U.S. pension plan.

     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


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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



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Notes to the Consolidated Financial Statements
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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  
 


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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.
      


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Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
 
 
 
NOTE 23. OTHER CONTINGENCIES AND COMMITMENTS — Continued
      
     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 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.
     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
      


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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  
 
 1 2003 amount is the company’s share of a capital stock transaction of its Dynegy affiliate, which, under the applicable accounting rules, was recorded
    directly to retained earnings.
 2 See Note 2 on page FS-30 for explanation of extraordinary item.
 3 Includes a net loss of $200 for the adoption of FAS 143 and a gain of $4 for the company’s share of Dynegy’s cumulative effect of adoption of EITF No. 02-3.

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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  
 


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Quarterly Results and Stock Market Data
Unaudited
                                                                 
    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 )
3   
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 the net income for the period.
      
     The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX) and on the Pacific Exchange. As of February 25, 2004, stockholders of record numbered approximately 239,000. Through October 9, 2001, the common stock traded under the name of Chevron Corporation (trading symbol: CHV).
     There are no restrictions on the company’s ability to pay dividends.

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Five-Year Financial Summary
 
                                         
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 PRINCIPLES
1
  $ 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 PRINCIPLES
1
  $ 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  
 
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.
   
»
Supplemental Information on Oil and Gas Producing Activities
Unaudited

 

 
In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (FAS 69), this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables V through VII present information on the
company’s estimated net proved reserve quantities; standardized measure of estimated discounted future net cash flows related to proved reserves; and changes in estimated discounted future net cash flows. The Africa geographic area includes activities principally in Nigeria, Angola, Chad, Republic of Congo and Democratic Republic of Congo. The Asia-Pacific geographic area includes activities principally in Australia, China, Indonesia, Kazakhstan, Partitioned Neutral Zone between Kuwait and Saudi


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SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
– Continued
 
Arabia, Papua New Guinea, the Philippines, and Thailand. The “Other” geographic category includes activities in the United Kingdom, Canada, Denmark, the Netherlands, Norway, Trinidad and Tobago, Colombia, Venezuela, Brazil, Argentina, and other countries. Amounts shown for affiliated companies are ChevronTexaco’s 50 percent equity share of Tengizchevroil (TCO), an exploration and production partnership operating in the Republic of Kazakhstan, and a
 
 
30 percent equity share of Hamaca, an exploration and production partnership operating in Venezuela. The company increased its ownership in TCO from 45 percent to 50 percent in January 2001.
     Amounts in the tables exclude the cumulative effect adjustment for the adoption of FAS 143, “Asset Retirement Obligations.” Refer to Note 25 on page FS-50.
      


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  
 
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.

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»
Supplemental Information on Oil and Gas Producing Activities – Continued
Unaudited

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

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TABLE III — RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES1

      
The company’s results of operations from oil and gas producing activities for the years 2003, 2002 and 2001 are shown in the following table. Net income from exploration and production activities as reported on pages FS-6 and FS-7 reflects income taxes computed on an effective rate basis. In accordance with FAS
      
    
       
No. 69, income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the net income amounts on pages FS-6 and FS-7.


                                                                 
    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  
 
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.

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»
Supplemental Information on Oil and Gas Producing Activities – Continued
 
Unaudited

TABLE IV – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES – UNIT PRICES AND COSTS1,2

                                                                 
    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  
 
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.

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.
     Proved reserves do not include additional quantities that may result from extensions of currently proved areas or from applying secondary or tertiary recovery processes not yet tested and determined to be economic.
     Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.
     Net reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.

 

 

 



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TABLE V – RESERVE QUANTITY INFORMATION – Continued


      
     ChevronTexaco operates, under a risked service agreement, Venezuela’s Block LL-652, located in the northeast section of Lake Maracaibo. ChevronTexaco is accounting for LL-652 as an oil and gas activity and, at December 31, 2003, had recorded 19 million barrels of proved crude oil reserves and 89 billion cubic feet of proved natural gas reserves.
      
      
      
     No reserve quantities have been recorded for the company’s other service agreement – the Boscan Field in Venezuela. During the year, an agreement was reached that extends production rights on the Chuchupa and other gas fields in Colombia.


                                                                                                                                 
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.
 

INFORMATION ON CANADIAN OIL SANDS NET PROVED RESERVES NOT INCLUDED ABOVE:

 
In addition to conventional liquids and natural gas proved reserves, ChevronTexaco has significant interests in proved oil sands reserves in Canada associated with the Athabasca project. For internal management purposes, ChevronTexaco views these reserves and their development as an integral part of total upstream operations. However, U.S. Securities and Exchange Commission regulations define these reserves as mining-related and not a part of conventional oil and gas reserves. Net proved oil sands reserves were 171 million barrels as of December 31, 2003. Production began in late 2002.
 
The oil sands reserves are not considered in the standardized measure of discounted future net cash flows for conventional oil and gas reserves, which is found on page FS-58.

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»
Supplemental Information on Oil and Gas Producing Activities – Continued
 
Unaudited

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

 
The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FAS No. 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions, 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  
 
*   2002 and 2001 include certain reclassifications to conform to 2003 presentation.

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

     The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production
 
volumes and costs. Changes in the timing of production are included with “Revisions of previous quantity estimates.”


                                                                         
    Consolidated Companies     Affiliated Companies     Worldwide  
Millions of dollars   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  
 

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EXHIBIT INDEX

         
Exhibit No. Description


  3 .1   Restated Certificate of Incorporation of ChevronTexaco Corporation, dated October 9, 2001, filed as Exhibit 3.1 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
  3 .2   By-Laws of ChevronTexaco Corporation, as amended September 26, 2001, filed as Exhibit 3.2 for ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.
        Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the corporation and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Commission upon request.
  10 .1   ChevronTexaco Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, approved by the company’s stockholders on May 22, 2003, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated 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).

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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).

Filed herewith.

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

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

E-2

exv10w3
 

Exhibit 10.3

CHEVRONTEXACO CORPORATION
EXCESS BENEFIT PLAN

Amended and Restated as of April 1, 2002

SECTION 1.      INTRODUCTION.

          The ChevronTexaco Corporation Excess Benefit Plan (the “Excess Benefit Plan”) was originally established effective January 1, 1976. Effective as of April 1, 2002, the Excess Benefit Plan was last amended and restated to read as set forth herein. The purposes of the Excess Benefit Plan are: (i) to supplement benefits provided under the Retirement Plan, to the extent such benefits are reduced as a result of the limitation on regular earnings imposed under section 401(a)(17) of the Code or the limitations on annual pension benefits imposed under section 415 of the Code; (ii) to provide retirement benefits that take into account Unrestricted Awards made under the MIP, the Aramco ICP and the Caltex AIP, and salary deferrals under the Deferred Compensation Plan; and (iii) to supplement employer-provided benefits under the ESIP to the extent such benefits are reduced as a result of the limitation on regular earnings imposed under section 401(a)(17) of the Code, the dollar limitation on “annual additions” imposed under section 415(c)(1)(A) of the Code or salary deferrals under the Deferred Compensation Plan.

SECTION 2.      ELIGIBILITY AND PARTICIPATION.

          Participation in the Excess Benefit Plan shall be limited to:

                    (i)     All Members of the Retirement Plan whose benefits thereunder are reduced because of the limitations imposed under section 401(a)(17) or 415 of the Code;

                    (ii)     All Members of the Retirement Plan who receive Unrestricted Awards under the MIP, the Aramco ICP or the Caltex AIP;

                    (iii)     All Members of the Retirement Plan or ESIP who defer salary under the Deferred Compensation Plan; and

                    (iv)     All Members of the ESIP whose allocations of Company Contributions thereunder are reduced because of the limitations imposed under section 401(a)(17) or 415(c)(1)(A) of the Code.

SECTION 3.      PLAN BENEFITS.

          Plan Benefits under the Excess Benefit Plan shall consist of the Retirement Excess Benefit and the ESIP Excess Benefit. No Participant shall be entitled to Plan Benefits until the Participant ceases to be an Employee.

          (a)     Retirement Excess Benefit. A Participant’s Retirement Excess Benefit shall be the sum of (i) and (ii) below:

                    (i)     The lump sum value of an Individual Life Pension, determined by subtracting the Individual Life Pension to which the Participant is entitled under the Retirement Plan from the Individual Life Pension to which the Participant would be entitled thereunder without regard to the Section 401(a)(17) and

-1-


 

Exhibit 10.3

Section 415 Reductions and the Participant’s salary deferrals under the Deferred Compensation Plan. In addition, a Participant’s Retirement Excess Benefit shall include any Interest payable under the Retirement Plan that may not be paid from that Plan because of the limitations imposed under section 415 of the Code. Any such Interest shall be paid or credited, as appropriate, at the time payments are made from the Retirement Plan.

                    (ii)     The lump sum value of an Individual Life Pension, determined as follows:

                              (A)     The Participant’s MIP Excess Benefit Earnings shall be determined by subtracting the Participant’s Highest Average Earnings from the amount that would constitute the Participant’s Highest Average Earnings if the Participant’s Unrestricted Awards under the MIP, the Aramco ICP and the Caltex AIP, as determined by the Committee in its sole discretion, were taken into account as Regular Earnings.

                              (B)     “Unrestricted Awards” with respect to the MIP means any awards under the MIP that are not subject to forfeiture conditions established by the Committee (other than the forfeiture conditions expressly described in the text of the MIP). “Unrestricted Awards” with respect to the Aramco ICP means any awards under the Aramco ICP that are taken into account under the Aramco Plan prior to 1989. “Unrestricted Awards” with respect to the Caltex AIP means any awards under the Caltex AIP that are taken into account under the Caltex Plan.

                              (C)     Each Unrestricted Award under the MIP shall be deemed paid in equal monthly installments for that portion of the MIP Award Year during which the Participant was an Employee and a participant in the MIP, without regard to when the Participant is informed of such Award or when such Award is actually paid. If an Unrestricted Award under the MIP is made after the close of the applicable MIP Award Year, if necessary, the Committee shall recalculate the Participant’s Plan Benefit solely for the purpose of taking such Award into consideration. For purposes of any such recalculation, the Committee shall not credit the Participant with any interest nor make any other change in the methods, factors or assumptions used in the original calculation. All Unrestricted Awards under the Aramco ICP and/or the Caltex AIP shall be deemed paid in equal monthly installments for that portion of the award year under the Aramco Plan and the Caltex Plan, respectively, during which the Participant was a participant in such Plan.

                              (D)     The Participant’s MIP Credited Service shall be that portion of the Participant’s Period of Service which is taken into account in computing the Participant’s Plan Benefit under the Retirement Plan, excluding all service prior to the date on which the Participant reaches age 25 that occurs before July 1, 1986.

                              (E)     An Individual Life Pension shall be determined under the applicable formula set forth in sections 3(c), 4(c) and 6(d) of the Retirement Plan, on the basis of the Participant’s MIP Excess Benefit Earnings and MIP Credited Service, without regard to any Social Security Offset provided in such formula.

          (b)     Calculation of Retirement Excess Benefit.

                    (i)     The lump sum value of a Participant’s Retirement Excess Benefit shall be the present value of the Individual Life Pension described in Section 3(a) above. Such present value shall be computed under whichever of the following rules is applicable:

                              (A)     If the Participant elects to have his or her Plan Benefit under the Retirement Plan paid in the form of a monthly pension, such present value shall be computed under the rules and assumptions that would be used for calculating the payment of such Individual Life Pension under the Lump Sum Option of the Retirement Plan, based on the Participant’s age and the interest rates in effect on the first day of the first month for which the Retirement Plan pension is paid; or

-2-


 

Exhibit 10.3

                              (B)     If the Participant elects to have his or her Plan Benefit under the Retirement Plan paid under the Lump Sum Option, such present value shall be computed under the same rules and assumptions and shall be determined as of the same date used for the calculation of the basic amount of the lump sum payment from the Retirement Plan.

                    (ii)     Interest shall accrue on the unpaid portion, if any, of a Participant’s Retirement Excess Benefit, commencing on the last day of the month after the month as of which the lump sum value of such Excess Benefit is calculated. If a Participant receives an Unrestricted Award under the MIP after termination of employment, any additional Retirement Excess Benefit attributable to that Award shall accrue interest commencing as of the first day of the month after the month in which the Award is granted. Interest shall be credited and compounded at the end of each Quarter at a rate equal to the average market yield for the preceding Quarter on U.S. Government 10-year bonds, constant maturity, as published by Data Resources Inc. in Data Resources Review of the U.S. Economy, or in such other source as the Committee may from time to time prescribe.

          (c)     ESIP Excess Benefit. A Participant’s ESIP Excess Benefit shall be the lump sum value of a Participant’s Stock Units, determined as follows:

                    (i) The Committee shall establish an ESIP Excess Benefit Account for each Participant whose share of Company Contributions under the ESIP is reduced for any payroll period on account of the Section 401(a)(17) or Section 415(c)(1)(A) Reductions or on account of deferrals under the Deferred Compensation Plan. Stock Units shall be credited to such Account as set forth in (ii) and (iii) below.

                    (ii)     As of the close of each payroll period, each Participant’s ESIP Excess Benefit Account shall be credited with the number of Stock Units determined by subtracting the amount of Company Contributions allocated to such Participant’s Accounts under the ESIP for such payroll period from the amount of Company Contributions that would have been allocated to such Participant for such payroll period without regard to the Section 401(a)(17) and Section 415(c)(1)(A) Reductions and the Participant’s deferrals under the Deferred Compensation Plan, and by dividing the resulting amount by the per share price used in allocating the Company Contribution under the ESIP for such payroll period.

                    (iii)     As of the payment date of a cash dividend paid with respect to shares of ChevronTexaco Stock, each Participant’s ESIP Excess Benefit Account shall be credited with the number of Stock Units determined by multiplying the number of Stock Units in such Account on the appropriate dividend payment date by the per share amount of such dividend, and by dividing the resulting amount by the average share price obtained in connection with the reinvestment of the dividend in the non-leveraged ESOP stock fund within the ESIP.

          (d)     Integration with Gulf SPP Benefits. The Retirement Excess Benefit of any Participant who is an Eligible Employee under the Gulf SPP shall be reduced as follows. Before conversion to a present lump sum value, the Individual Life Pension determined under Section 3(a) above with respect to the Participant’s MIP Credited Service completed before July 1, 1986, shall be reduced (but not below zero) by the Participant’s net Gulf SPP individual life pension (determined after the application of all offsets under the Gulf SPP for qualified pension plan benefits). Any Spouse-Pension or Gulf Retirement Bonus provided under the Gulf SPP shall be ignored.

SECTION 4.      DISTRIBUTION OF PLAN BENEFITS.

          Distribution of Plan Benefits hereunder shall be made in cash after the Participant ceases to be an Employee at such time or times as the Committee shall determine in its sole discretion. A Participant who is employed by Chevron Phillips Chemical JV shall be deemed to have ceased to be an Employee for this purpose

-3-


 

Exhibit 10.3

(i) in the case of the Retirement Excess Benefit, upon the earlier of the date when he or she is eligible for early retirement under the Retirement Plan or the date his or her employment with Chevron Phillips Chemical JV terminates; and (ii) in the case of the ESIP Excess Benefit, on the date his or her employment by the Corporation and its subsidiaries and affiliates (other than Chevron Phillips Chemical JV) terminates. The Committee has established the following guidelines for determining the time of distribution of Plan Benefits:

          (a)     Retirement Excess Benefit.

                    (i)     In no event shall distribution of the Participant’s Retirement Excess Benefit be made prior to the date payment of the Participant’s benefit under the Retirement Plan is made or commences.

                    (ii)     Unless the Committee approves a Participant’s distribution request pursuant to Section 4(a)(iii) below, distribution of the Participant’s Retirement Excess Benefit shall commence in the first January, April, July or October that is at least 12 months after the Participant ceases to be an Employee and shall be made in ten approximately equal annual installments. All installments after the first shall be paid in January.

                    (iii)     Within 30 days after the date a Participant ceases to be an Employee, the Participant may make a request for distribution at the time and in the manner described in (A) or (B) below by filing the prescribed form with the Committee. Distribution of the Participant’s Retirement Excess Benefit shall be made in accordance with such request unless the Committee has disapproved the Participant’s request or has determined that the distribution shall be made at some other time; provided, however, that (1) no distribution may be made pursuant to such request within the 12-month period commencing on the date the request is filed with the Committee and (2) any distribution scheduled to be made within such 12-month period pursuant to Section 4(a)(ii) above shall be made without regard to the request made pursuant to this Section 4(a)(iii):

                              (A)     In a lump sum in any January, April, July or October after the Participant ceases to be an Employee, but not later than the first January after the later of the date the Participant attains age 70 1/2 or the date the Participant ceases to be an Employee;

                              (B)     In fifteen or fewer approximately equal annual installments, commencing in any January, April, July or October after the Participant ceases to be an Employee, but not later than the first January after the later of the date the Participant attains age 70 1/2 or the date the Participant ceases to be an Employee. All installments after the first shall be paid in January.

                    (iv)     Distribution of a Participant’s Retirement Excess Benefit shall be made in accordance with the Participant’s request, unless the Committee has disapproved the request or has determined that the distribution shall be made at some other time.

                    (v)     The amount of any installment payment shall be determined by dividing the unpaid balance of the Participant’s Retirement Excess Benefit, including credited interest, as of the close of the Quarter preceding the distribution date, by the number of annual payments remaining to be made. The last installment payment shall include interest for the Quarter in which such payment is made.

                    (vi)     The time of distribution pursuant to Section 4(a)(ii) or (iii) above may only be changed by the Committee. A Participant may request such a change by describing to the Committee in writing the Participant’s reason for such request. The Committee shall approve such change only upon a showing of hardship or significantly changed circumstances based on substantial evidence.

-4-


 

Exhibit 10.3

                    (vii)     In the event that a Participant receives an Unrestricted Award under the MIP after the date distribution of such Participant’s Retirement Excess Benefit is made or commenced pursuant to Section 4(a)(ii) or (iii) above, the following rules shall apply:

                              (A)     If the Participant received a single payment pursuant to Section 4(a)(iii)(A) above, the additional Retirement Excess Benefit attributable to such Unrestricted Award under the MIP shall be paid in a lump sum as soon as practicable; and

                              (B)     If the Participant commenced to receive installment payments pursuant to Section 4(a)(ii) or (iii)(B) above, such Participant’s future installment payments shall be recalculated to reflect the additional Retirement Excess Benefit attributable to such Unrestricted Award under the MIP.

                    (viii)     In the event that the balance in a Participant’s Account is less than $50,000 on the date the Participant ceases to be an Employee, then any provision of this Section 4(a) to the contrary notwithstanding, payment shall be made in a lump sum as soon as reasonably practicable following the last business day of the Quarter following the Quarter in which the Participant ceased to be an Employee. Such payment shall be based on the value of the Participant’s Account as of the last business day of the Quarter following the Quarter in which the Participant ceased to be an Employee. This Section 4(a)(viii) shall not apply to a Participant who ceased to be an Employee before April 1, 2002.

          (b)     ESIP Excess Benefit.

                    (i)     Unless the Committee approves a Participant’s distribution request pursuant to Section 4(b)(ii) below, distribution of the value of the Stock Units credited to the Participant’s ESIP Excess Benefit Account shall commence in the first January, April, July or October that is at least 12 months after the Participant ceases to be an Employee and shall be made in ten approximately equal annual installments. All installments after the first shall be paid in January.

                    (ii)     Within 30 days after the date a Participant ceases to be an Employee, the Participant may make a request for distribution at the time and in the manner described in (A) or (B) below by filing the prescribed form with the Committee. Distribution of the value of the Stock Units credited to the Participant’s ESIP Excess Benefit Account shall be made in accordance with the first such request made after December 31, 1996, unless the Committee has disapproved the Participant’s request or has determined that the distribution shall be made at some other time; provided, however, that (1) no distribution may be made pursuant to such request within the 12-month period commencing on the date the request is filed with the Committee and (2) any distribution scheduled to be made within such 12-month period pursuant to Section 4(b)(i) above shall be made without regard to the request made pursuant to this Section 4(b)(ii):

                              (A)     In a lump sum in any January, April, July or October after the Participant ceases to be an Employee, but not later than the first January after the later of the date the Participant attains age 70 1/2 or the date the Participant ceases to be an Employee;

                              (B)     In fifteen or fewer approximately equal annual installments, commencing in any January, April, July or October after the Participant ceases to be an Employee, but not later than the first January after the later of the date the Participant attains age 70 1/2 or the date the Participant ceases to be an Employee. All installments after the first shall be paid in January.

-5-


 

Exhibit 10.3

                    (iii)     Distribution of a Participant’s ESIP Excess Benefit shall be made in accordance with the Participant’s request, unless the Committee has disapproved the request or has determined that the distribution shall be made at some other time.

                    (iv)     The amount of a cash payment pursuant to Section 4(b)(i) or (ii) shall be determined by dividing the number of Stock Units credited to the Participant’s ESIP Excess Benefit Account as of the close of the Quarter preceding the distribution date by the number of annual payments remaining to be made, and by converting the resulting number of Stock Units to a cash amount by multiplying such number of Stock Units by the average daily trade price for the leveraged ESOP stock fund within the ESIP as of the last business day of the Quarter preceding the date payment is made under the Excess Benefit Plan.

                    (v)     The time of distribution pursuant to Section 4(b)(i) or (ii) above may only be changed by the Committee. The Participant may request such a change by writing to the Committee setting forth the Participant’s reason for such request. The Committee shall approve such distribution only upon a showing of hardship or significantly changed circumstances based on substantial evidence.

                    (vi)     In the event that the balance in a Participant’s Account is less than $50,000 on the date the Participant ceases to be an Employee, then any provision of this Section 4(b) to the contrary notwithstanding, payment shall be made in a lump sum as soon as reasonably practicable following the last business day of the Quarter following the Quarter in which the Participant ceased to be an Employee. Such payment shall be based on the value of the Participant’s Account as of the last business day of the Quarter following the Quarter in which the Participant ceased to be an Employee. This Section 4(b)(vi) shall not apply to a Participant who ceased to be an Employee before April 1, 2002.

          (c)     Benefits in Pay Status on July 1, 1996. Notwithstanding the foregoing provisions of this Section 4, Plan Benefits in pay status on July 1, 1996 shall continue to be paid in accordance with the terms of the Excess Benefit Plan as in effect prior to July 1, 1996, except that all installment payments after the first shall be paid in January.

SECTION 5.      DEATH BENEFITS.

          (a)     Retirement Excess Benefit.

                    (i)     If a Participant dies after ceasing to be an Employee, the unpaid portion of the Participant’s Retirement Excess Benefit shall be distributed to the Participant’s Beneficiary in accordance with Section 5(c).

                    (ii)     If a Participant ceases to be an Employee by reason of death and the Participant’s Beneficiary under the Retirement Plan is entitled to a Pre-Retirement Lump Sum Death Benefit under the Retirement Plan, the Participant’s Retirement Excess Benefit shall be distributed to the Participant’s Beneficiary in accordance with Section 5(c). The lump sum value of such Excess Benefit shall be determined as of the first day of the month following the month in which the Participant dies.

                    (iii)     If a Participant ceases to be an Employee by reason of death and the Participant’s surviving spouse is entitled to a Pre-Retirement Spouse Pension under the Retirement Plan, a portion of the Participant’s Retirement Excess Benefit shall be distributed to the Participant’s surviving spouse. Such portion shall be calculated in the manner prescribed in Sections 9(b)(ii) and 9(c)(ii)(B) of the Retirement Plan. Such distribution to the Participant’s surviving spouse shall be made in accordance with Section 5(c).

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Exhibit 10.3

          (b)     ESIP Excess Benefit.

                    (i)     If a Participant dies after ceasing to be an Employee, the unpaid portion of the Participant’s ESIP Excess Benefit shall be distributed to a Participant’s Beneficiary in accordance with Section 5(c).

                    (ii)     If a Participant ceases to be an Employee by reason of death, his or her ESIP Excess Benefit shall be distributed to the Participant’s Beneficiary in accordance with Section 5(c).

          (c)     Beneficiaries. A Participant may designate on the prescribed form filed with the Committee one or more Beneficiaries to receive payment of any Plan Benefits hereunder that become distributable after the Participant’s death. A Participant may change such designation at any time by filing the prescribed form with the Committee. If a Beneficiary has not been designated or if no designated Beneficiary survives the Participant, distribution will be made to the Participant’s surviving spouse as Beneficiary if such spouse is then living or, if not, in equal shares to the then living children of the Participant as Beneficiaries or, if none, to the Participant’s estate as Beneficiary. Distributions under this Section 5(c) will be made in such manner and at such times as the Committee shall determine in its sole discretion. Unless the Committee directs otherwise, the elections provided in Section 4 may be made by the Beneficiary following the Participant’s death.

SECTION 6.      MISCELLANEOUS.

          (a)     Forfeitures. Plan Benefits which are unpaid shall be forfeited under the following circumstances:

                    (i)     If the Participant is dismissed for cause or otherwise ceases to be an Employee at a time when a basis for such dismissal exists; or

                    (ii)     If, before or after the Participant ceases to be an Employee, the Participant engages in any activity which, in the opinion of the Committee, is prejudicial to the interests of any member of the Affiliated Group; or

                    (iii)     If the Participant is indebted to any member of the Affiliated Group at the time he or she becomes entitled to payment of a Plan Benefit hereunder. In such a case, to the extent that the amount of the Plan Benefit does not exceed such indebtedness, the amount of such Plan Benefit shall be forfeited and the Participant’s indebtedness shall be extinguished to the extent of such forfeiture. The Committee in its sole discretion shall determine how and why such forfeiture shall be effected, including the valuation of any Stock Units credited to the Participant’s ESIP Excess Benefit Account. Any forfeiture under this Section 6(a)(iii) shall be deemed to come first from the Participant’s Retirement Excess Benefit and then from his or her ESIP Excess Benefit.

          (b)     Funding. The Excess Benefit Plan shall be unfunded, and all Plan Benefits shall be paid only from the general assets of ChevronTexaco Corporation.

          (c)     Tax Withholding. All distributions shall be net of any necessary payroll deductions including, but not limited to, income tax withholding required by federal, state or local law. In addition, any withholding required under the Federal Insurance Contributions Act or the Federal Unemployment Tax Act (and any income tax withholding attributable thereto) with respect to a Participant’s Retirement Excess Benefit prior to the date a distribution is made from the Excess Benefit Plan shall be debited from the Participant’s Retirement Excess Benefit.

          (d)     No Employment Rights. Nothing in this Excess Benefit Plan shall be deemed to give any individual a right to remain in the employ of any member of the Affiliated Group nor affect the right of a member of the Affiliated Group to terminate any individual’s employment at any time and for any reason, which right is hereby reserved.

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Exhibit 10.3

          (e)     No Assignment of Property Rights. Except as otherwise provided in Section 6(a)(iii) with respect to a Participant’s indebtedness to any member of the Affiliated Group, or except as otherwise provided by applicable law, the interest or property rights of any person in the Excess Benefit Plan or in any distribution to be made hereunder shall not be assigned (either at law or in equity), alienated, anticipated or subject to attachment, bankruptcy, garnishment, levy, execution or other legal or equitable process. Any act in violation of this Section 6(e) shall be void. Notwithstanding the foregoing, the creation, assignment or recognition of a right to all or any portion of a Participant’s Plan Benefit hereunder pursuant to a “qualified domestic relations order,” (within the meaning of section 414(p) of the Code) shall not constitute a violation of this Section 6(e).

          (f)     Effect of Change in Capitalization on ESIP Excess Benefit Accounts. In the event of a stock split, stock dividend or other change in capitalization affecting ChevronTexaco Stock, an appropriate number of Stock Units shall be substituted for, or added to, each Stock Unit then credited to the ESIP Excess Benefit Account of each Participant, and such substituted or added Unit shall be subject to the same terms and conditions as the original Unit.

          (g)     Administration. The Excess Benefit Plan shall be administered by the Committee. No member of the Committee shall become a Participant in the Excess Benefit Plan. The Committee shall make such rules, interpretations and computations as it may deem appropriate. The Committee shall have sole discretion to interpret the terms of the Excess Benefit Plan, and any decision of the Committee with respect to the Excess Benefit Plan, including (without limitation) any determination of eligibility to participate in the Excess Benefit Plan and any calculation of Plan Benefits shall be conclusive and binding on all persons.

          (h)     Amendment and Termination. ChevronTexaco Corporation expects to continue the Excess Benefit Plan indefinitely. Future conditions, however, cannot be foreseen, and ChevronTexaco Corporation shall have the authority to amend or to terminate the Excess Benefit Plan at any time and for any reason, by action of its board of directors or by action of a committee or individual(s) acting pursuant to a valid delegation of authority. In the event of the amendment or termination of the Excess Benefit Plan, a Participant’s Retirement Excess Benefit and ESIP Excess Benefit shall not be less than the amounts to which he or she would have been entitled if his or her employment had terminated immediately prior to such amendment or termination.

          (i)     Successors And Assigns. The Excess Benefit Plan shall be binding upon the Corporation, its Successors and Assigns. Notwithstanding that the Excess Benefit Plan may be binding upon a Successor or Assign by operation of law, the Corporation shall require any Successor or Assign to expressly assume and agree to be bound by the Excess Benefit Plan in the same manner and to the same extent that the Corporation would be if no succession or assignment had taken place.

SECTION 7.      CHANGE IN CONTROL

          Notwithstanding any other provisions of this Excess Benefit Plan to the contrary, the provisions of this Section 7 shall apply during the Benefit Protection Period.

          (a)     Restrictions on Amendments During Benefit Protection Period. Notwithstanding Section 6(h) of the Excess Benefit Plan, except to the extent required to comply with applicable law, no amendment of the Excess Benefit Plan (other than an amendment to reduce or discontinue future accruals under the Excess Benefit Plan) that is executed or first becomes effective during the Benefit Protection Period shall:

                    (i)     Deprive any individual who is a Participant on the Benefit Protection Period Commencement Date or immediately prior to a Change in Control of coverage under the Excess Benefit Plan as constituted at the time of such amendment;

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Exhibit 10.3

                    (ii)     Deprive any individual who is a Beneficiary with respect to an individual who is a Participant on the Benefit Protection Period Commencement Date or immediately prior to a Change in Control of any benefit to which he or she is entitled on the Benefit Protection Period Commencement Date or may become entitled during the Benefit Protection Period;

                    (iii)     Reduce the amount of benefits provided under the Excess Benefit Plan below the benefits provided under the Excess Benefit Plan on the day prior to the Benefit Protection Period Commencement Date;

                    (iv)     Amend Sections 6(I), 7, 8.4, 8.5, 8.8, or 8.32 of the Excess Benefit Plan; or

                    (v)     Terminate the Excess Benefit Plan.

For purposes of this Section 7, approval shall mean written approval (by a person or entity within ChevronTexaco Corporation having the authority to do so) of such amendment or termination.

          (b)     Exception to Section 7(a). Section 7(a) shall not apply to the extent that (i) the amendment or termination of the Excess Benefit Plan is approved after any plans have been abandoned to effect the transaction which, if effected, would have constituted a Change in Control and the event which would have constituted the Change in Control has not occurred, and (ii) within a period of six months after such approval, no other event constituting a Change in Control shall have occurred, and no public announcement of a proposed event which would constitute a Change in Control shall have been made, unless thereafter any plans to effect the Change in Control have been abandoned and the event which would have constituted the Change in Control has not occurred.

          (c)     Restrictions on Certain Actions Prior to or Following, a Change in Control. Notwithstanding any contrary provisions of the Excess Benefit Plan and except to the extent required to comply with applicable law, (1) any amendment or termination of the Excess Benefit Plan which is executed or would otherwise become effective prior to a Change in Control at the request of a third party who effectuates a Change in Control shall not be an effective amendment or termination of the Excess Benefit Plan during the Benefit Protection Period; and (2) the Excess Benefit Plan shall not be amended at any time if to do so would adversely affect the rights derived under the Excess Benefit Plan from this Section 7 of any individual who is a Member of the Retirement Plan or the ESIP during the Benefit Protection Period or a Beneficiary with respect to a Participant during the Benefit Protection Period. Furthermore, following a Change in Control, no person shall take any action that would directly or indirectly have the same effect as any of the prohibited amendments listed in Section 7(a).

          (d)     Effect on other Benefits. In calculating a Participant’s Retirement Plan Excess Benefit under Section 3(a) and MIP Excess Benefit under Section 3(c), it shall be assumed that the Retirement Plan formula in effect on the Benefit Protection Period Commencement Date had continued in effect through the date the Participant’s employment with the Affiliated Group terminates.

          (e)     ESIP Excess Benefit. Each of a Participant’s Stock units shall be converted to a dollar amount immediately after a Change in Control in an amount equal to the greater of (1) the highest price paid per share of ChevronTexaco Stock (the “Shares”) paid to holders of the Shares in any transaction (or series of transactions) constituting or resulting in a Change in Control or (2) the highest closing price of a Share as reported on the New York Stock Exchange, Inc. composite transaction report during the ninety-day period ending on the date of a Change in Control. Thereafter interest shall be added to the unpaid portion of the total dollar amount of the Participant’s ESIP Excess Benefit in the manner described in Section 4(b)(iv).

-9-


 

Exhibit 10.3

          (f)     MIP Excess Benefit. References to MIP in the Excess Benefit Plan shall include the Management Incentive Plan of ChevronTexaco Corporation and any alternative plan or program established to provide incentive awards in lieu of those provided under the Management Incentive Plan.

          (g)     Distribution of Plan Benefits. Each Participant’s Plan Benefits shall be distributed in a single lump sum cash payment immediately after the later of the date of the Change in Control or the date the Participant’s employment with the Affiliated Group terminates.

          (h)     Establishment of a Trust. Notwithstanding anything contained in this Excess Benefit Plan to the contrary, nothing herein shall prevent or prohibit the Corporation from establishing a trust or other arrangement for the purpose of providing for the payment of the benefits payable under this Excess Benefit Plan.

          (i)     No Forfeitures. Plan Benefits shall not be subject to forfeiture under any circumstances, including the circumstances provided in Section 6(a) of the Excess Benefit Plan.

          (j)     Miscellaneous.

                    (i)     Notwithstanding anything contained in the Excess Benefit Plan to the contrary, no Participant shall be required to mitigate the amount of any payment or benefit provided for in the Excess Benefit Plan by seeking other employment or otherwise and no such payment shall be offset or reduced by the amount of any compensation or benefits provided to any participant in any subsequent employment.

                    (ii)     The provisions of the Excess Benefit Plan shall be deemed severable and the validity or enforceability of any provision shall not affect the validity or enforceability of the other provisions hereof.

                    (iii)     The Corporation’s obligation to make the payments and provide the benefits provided for in the Excess Benefit Plan and otherwise to perform its obligation hereunder shall not be affected by any circumstances, including, without limitation, any set-off, counterclaim, recoupment, defense or other right which the Corporation may have against the Participant or others.

                    (iv)     No provision of the Excess Benefit Plan may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by the Participant and the corporation. No waiver by either party hereto at any time of breach by the other party hereto of, or compliance with, any condition or provision of the Excess Benefit Plan to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or any prior or subsequent time.

SECTION 8.      DEFINITIONS.

          Except as provided below, capitalized terms used in the Excess Benefit Plan shall have the same meaning as in the Retirement Plan or ESIP, as appropriate:

          8.1     “Aramco ICP” means the Arabian American Oil Company Incentive Compensation Plan.

          8.2     “Aramco Plan” means the Arabian American Oil Company Supplementary Retirement Plan.

          8.3     “Beneficiary” means the person or persons entitled to receive a Participant’s Plan Benefit in the event the Participant dies prior to receiving the entire amount of such Plan Benefit, as provided in Section 5(c).

          8.4     “Benefit Protection Period” means the period commencing on the Benefit Protection Period Commencement Date and terminating two years after the date of a Change in Control.

-10-


 

Exhibit 10.3

          8.5     “Benefit Protection Period Commencement Date” means the date six months prior to the public announcement of the proposed transaction which, when effected, is a Change in Control.

          8.6     “Caltex AIP” means the Caltex-Amoseas Annual Incentive Plan.

          8.7     “Caltex Plan” means the Pension Supplementation Plan of Caltex Corporation.

          8.8     “Change in Control” means a change in control of the Corporation as defined in Article VI of the Corporation’s By-Laws, as it may be amended from time-to-time.

          8.9     “Code” means the Internal Revenue Code of 1986, as amended.

          8.10     “Committee” means the Management Compensation Committee of the Board of Directors of ChevronTexaco Corporation.

          8.11     “Composite Transaction Report” means the New York Stock Exchange, Inc. Composite Transaction Report, or such other stock report as the Committee from time to time may designate.

          8.12     “Corporation” means ChevronTexaco Corporation, a Delaware corporation.

          8.13     “Deferred Compensation Plan” means the ChevronTexaco Corporation Deferred Compensation Plan for Management Employees (formerly the Salary Deferral Plan for Management Employees).

          8.14     “Employee” means an individual who is on the U. S. dollar payroll of and is rendering services to ChevronTexaco Corporation or one of its subsidiaries or affiliates.

          8.15     “ESIP” means the ChevronTexaco Corporation Employee Savings Investment Plan.

          8.16     “ESIP Excess Benefit” means the benefit described in Section 3(c).

          8.17     “ESIP Excess Benefit Account” means the account described in Section 3(c)(i).

          8.18     “Gulf SPP” means the Supplemental Pension Plan of Gulf Oil Corporation.

          8.19     “Gulf SPP Benefit” means the benefits provided for in the Gulf SPP, other than the Special Retirement Bonus provided for in Section 11 thereof.

          8.20     “MIP” means the Management Incentive Plan of ChevronTexaco Corporation.

          8.21     “MIP Award Year” means the calendar year with respect to which an award is made under the MIP.

          8.22     “MIP Credited Service” is defined in Section 3(a)(ii)(D).

          8.23     “MIP Excess Benefit Earnings” is defined in Section 3(a)(ii)(A).

          8.24     “Participant” means a person who is eligible to participate in the Excess Benefit Plan as provided in Section 2.

          8.25     “Plan Benefit” means the benefits described in Section 3.

          8.26     “Plan Year” means the calendar year.

          8.27     “Quarter” means a calendar quarter.

          8.28     “Retirement Excess Benefit” means the benefit described in Section 3(a).

-11-


 

Exhibit 10.3

          8.29     “Retirement Plan” means the ChevronTexaco Corporation Retirement Plan, including all Supplements thereto.

          8.30     “Section 401(a)(17) Reduction” means, as the context may require, (i) any reduction in the allocation of Company Contributions to a Participant by reason of the limitation on Member Contributions that is required to comply with section 401(a)(17) of the Code, and (ii) any reduction in a Participant’s Plan Benefit under the Retirement Plan by reason of the limitation on Regular Earnings that is required to comply with section 401(a)(17) of the Code.

          8.31     “Section 415 Reduction” means any reduction in a Participant’s Plan Benefit under the Retirement Plan that is required to comply with any of the limitations on annual pension benefits imposed under section 415 of the Code.

          8.32     “Section 415(c)(1)(A) Reduction” means any reduction in the allocation of Company Contributions to a Participant that is required to comply with the dollar limitation on “annual additions” imposed under section 415(c)(1)(A) of the Code. “Section 415(c)(i)(A) Reduction” shall not include any reduction with respect to any special allocation made pursuant to Section 24.5 of the ESIP, as amended from time to time, with respect to a “change in control” as that term is defined in such Section 24.5 of the ESIP.

          8.33     “Spouse-Pension” means the Spouse-Pension provided for in the Gulf SPP.

          8.34     “Stock Units” means the ChevronTexaco stock equivalents credited to a Participant’s ESIP Excess Benefit Account in accordance with Section 3(c).

          8.35     “Successors and Assigns” means a corporation or other entity acquiring all or substantially all the assets and business of the ChevronTexaco Corporation (including the Plan) whether by operation of law or otherwise.

          8.36     “Unrestricted Award” means a nonforfeitable award under the MIP, Aramco ICP or Caltex AIP, as described in Sections 3(a)(ii)(B) and (C).

SECTION 9.      EXECUTION.

          To record the amendment and restatement of the Excess Benefit Plan to read as set forth herein effective as of April 1, 2002, ChevronTexaco Corporation has caused its authorized officer execute this document this first day of April, 2002.

         
 
       
    CHEVRONTEXACO CORPORATION
 
       
 
       
  By   /s/ David J. O’Reilly
     
 
      Chairman of the Board
 
       
  Date   April 1, 2002
     
 

-12-

exv12w1
 

Exhibit 12.1

ChevronTexaco Corporation — Total Enterprise Basis

Computation of Ratio of Earnings to Fixed Charges

(Dollars in Millions)

                                         
Year Ended December 31

2003 2002 2001 2000 1999





Net Income Before Extraordinary Item and Cumulative Effect of Changes in Accounting Principles
  $ 7,426     $ 1,132     $ 3,931     $ 7,727     $ 3,247  
Income Tax Expense
    5,344       3,024       4,360       6,322       2,565  
Distributions (Less) Greater Than Equity in Earnings of Affiliates
    (383 )     510       (489 )     (26 )     (288 )
Minority Interest
    80       57       121       111       71  
Previously Capitalized Interest Charged to Earnings During Period
    76       70       67       71       74  
Interest and Debt Expense
    474       565       833       1,110       1,132  
Interest Portion of Rentals*
    507       407       357       340       249  
     
     
     
     
     
 
Earnings Before Provision for Taxes and Fixed Charges
  $ 13,524     $ 5,765     $ 9,180     $ 15,655     $ 7,050  
     
     
     
     
     
 
Interest and Debt Expense
  $ 474     $ 565     $ 833     $ 1,110     $ 1,132  
Interest Portion of Rentals*
    507       407       357       340       249  
Preferred Stock Dividends of Subsidiaries
    4       5       48       50       55  
Capitalized Interest
    75       67       122       108       38  
     
     
     
     
     
 
Total Fixed Charges
  $ 1,060     $ 1,044     $ 1,360     $ 1,608     $ 1,474  
     
     
     
     
     
 
Ratio of Earnings to Fixed Charges
    12.76       5.52       6.75       9.74       4.78  

* Calculated as one-third of rentals. Considered a reasonable approximation of interest factor.

E-3

exv21w1
 

Exhibit 21.1

SUBSIDIARIES OF CHEVRONTEXACO CORPORATION*

At December 31, 2003
     
State or Country
Name of Subsidiary in Which Organized


Bermaco Insurance Company Limited
  Bermuda
Cabinda Gulf Oil Company Limited
  Bermuda
Caltex (Asia) Limited
  Delaware
Caltex New Zealand Limited
  New Zealand
Caltex Oil Corporation
  Delaware
Caltex Oil Hong Kong Limited
  Hong Kong
Caltex Oil (Kenya) Limited
  Kenya
Caltex Oil (Pakistan) Limited
  Bahamas
Caltex Oil (S.A.) (Proprietary) Limited
  South Africa
Caltex Oil (Thailand) Limited
  Bahamas
Caltex (Philippines) Inc.
  Philippines
Chevron Asiatic Limited
  Delaware
Chevron Australia Transport Pty. Ltd.
  Australia
Chevron Canada Capital Company
  Nova Scotia
Chevron Canada Finance Limited
  Canada
Chevron Canada Limited
  Canada
Chevron Capital Corporation
  Delaware
Chevron Capital U.S.A. Inc.
  Delaware
Chevron Caspian Pipeline Consortium Company
  Delaware
Chevron Credit Bank N. A.
  Utah
Chevron Environmental Management Company
  California
Chevron Environmental Services Company
  Delaware
Chevron Equatorial Guinea Ltd.
  Bermuda
Chevron Finance Company
  Delaware
Chevron International (Congo) Limited
  Bermuda
Chevron LNG Shipping Company Limited
  Bermuda
Chevron Nigeria Deepwater A Limited
  Nigeria
Chevron Nigeria Deepwater B Limited
  Nigeria
Chevron Nigeria Deepwater C Limited
  Nigeria
Chevron Nigeria Deepwater D Limited
  Nigeria
Chevron Nigeria Limited
  Nigeria
Chevron Niugini Limited
  Papua New Guinea
Chevron Oil Company (Nigeria) Limited
  Nigeria
Chevron Oil Congo (D.R.C.) Limited
  Bermuda
Chevron Oronite Company LLC
  Delaware
Chevron Oronite Pte. Ltd.
  Singapore
Chevron Oronite S.A.
  France
Chevron Overseas (Congo) Limited
  Bermuda
Chevron Overseas Company
  Delaware
Chevron Overseas Petroleum Brasil Limitada
  Brazil
Chevron Overseas Petroleum Limited
  Bahamas
Chevron Overseas Pipeline (Cameroon) Limited
  Bahamas
Chevron Overseas Pipeline (Chad) Limited
  Bahamas
Chevron Petroleum Chad Company Limited
  Bermuda
Chevron Petroleum Limited
  Bermuda
Chevron Pipe Line Company
  Delaware
Chevron San Jorge S.R.L.
  Argentina
Chevron Synfuels Limited
  Bermuda

E-4


 

     
State or Country
Name of Subsidiary in Which Organized


Chevron Thailand Inc.
  Delaware
Chevron Transport Corporation Ltd.
  Bermuda
Chevron U.K. Limited
  England
Chevron U.S.A. Inc.
  Pennsylvania
ChevronTexaco Australia Pty. Ltd.
  Australia
ChevronTexaco Capital Company
  Nova Scotia
ChevronTexaco Funding Corporation
  Delaware
ChevronTexaco Global Energy Inc.
  Delaware
ChevronTexaco Global Technology Services Company
  Delaware
ChevronTexaco International Limited
  Liberia
ChevronTexaco International Petroleum Company
  Delaware
ChevronTexaco Malampaya LLC
  Delaware
ChevronTexaco Overseas Petroleum Inc.
  Delaware
ChevronTexaco Petroleum Company
  New Jersey
ChevronTexaco Philippines Ltd.
  Bermuda
ChevronTexaco U.K. Limited
  England
ChevronTexaco Worldwide Gasification Technology Inc.
  Delaware
Four Star Oil & Gas Company
  Delaware
Fuel and Marine Marketing LLC
  Delaware
Getty Mining Company
  Delaware
Heddington Insurance Limited
  Bermuda
Insco Limited
  Bermuda
MVP Production Inc.
  Delaware
P.T. Caltex Pacific Indonesia
  Indonesia
Saudi Arabian Texaco Inc.
  Delaware
TEPI Holdings Inc.
  Delaware
Texaco Australia Pty. Ltd.
  Delaware
Texaco Block B South Natuna Sea Inc.
  Liberia
Texaco Brasil Ltda.
  Brazil
Texaco Britain Limited
  England
Texaco Capital Inc.
  Delaware
Texaco Capital LLC
  Turks and Caicos
Texaco Captain Inc.
  Delaware
Texaco Exploration and Production Inc.
  Delaware
Texaco Inc.
  Delaware
Texaco Investments (Netherlands) Inc.
  Delaware
Texaco Limited
  England
Texaco Natural Gas Inc.
  Delaware
Texaco Nederland B.V.
  Netherlands
Texaco North Sea U.K. Company
  Delaware
Texaco Overseas Holdings Inc.
  Delaware
Texaco Overseas (Nigeria) Petroleum Company Unlimited
  Nigeria
Texaco Power and Gasification Holdings Inc.
  Delaware
Texaco Raffinaderij Pernis B.V.
  Netherlands
Texaco Venezuela Holdings (I) Company
  Delaware
The Pittsburg & Midway Coal Mining Co.
  Missouri
Traders Insurance Limited
  Bermuda
TRMI Holdings Inc.
  Delaware
West Australian Petroleum Pty. Limited
  Western Australia

All of the subsidiaries in the above list are wholly owned, either directly or indirectly, by ChevronTexaco Corporation. Certain subsidiaries are not listed because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary at December 31, 2003.

E-5

exv23w1
 

Exhibit 23.1

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 33-58463, 333-91210 and 333-110487) of ChevronTexaco Corporation, and to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-102269, 333-72672, 333-21805, 333-21807, 333-21809, 333-26731, 333-46261, 033-3899, 033-34039, 033-35283, 333-105136) of ChevronTexaco Corporation, and to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-91210-01 and 333-110487-01) of ChevronTexaco Funding Corporation and ChevronTexaco Corporation, and to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-91210-02 and 333-110487-02) of ChevronTexaco Capital Company and ChevronTexaco Corporation, and to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-91210-03 and 333-110487-03) of Chevron Capital U.S.A. Inc. and ChevronTexaco Corporation, and to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-91210-04) of Chevron Canada Capital Company and ChevronTexaco Corporation, and to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-91210-05) of Chevron Capital Corporation and ChevronTexaco Corporation, and to the incorporation by reference in the Registration Statement on Form S-3 (No. 033-14307) of Chevron Capital U.S.A. Inc. and ChevronTexaco Corporation of our report dated February 25, 2004, relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP


PRICEWATERHOUSECOOPERS LLP

San Francisco, California

March 9, 2004

E-6

exv24w1
 

Exhibit 24.1

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ Samuel H. Armacost

 

exv24w2
 

Exhibit 24.2

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ Robert J. Eaton

 

exv24w3
 

Exhibit 24.3

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ Sam Ginn

 

exv24w4
 

Exhibit 24.4

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ Carla A. Hills

 

exv24w5
 

Exhibit 24.5

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ Franklyn G. Jenifer

 

exv24w6
 

Exhibit 24.6

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ J. Bennett Johnston

 

exv24w7
 

Exhibit 24.7

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
        /s/ Sam Nunn
 
 

 

exv24w8
 

Exhibit 24.8

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ Charles R. Shoemate
 
 

 

exv24w9
 

Exhibit 24.9

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ Frank A. Shrontz
 
 

 

exv24w10
 

Exhibit 24.10

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ Thomas A. Vanderslice
 
 

 

exv24w11
 

Exhibit 24.11

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ Carl Ware
 
 

 

exv24w12
 

Exhibit 24.12

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ John A. Young
 
 

 

exv24w13
 

Exhibit 24.13

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ David J. O’Reilly
 
 

 

exv24w14
 

Exhibit 24.14

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ Peter J. Robertson
 
 

 

exv24w15
 

Exhibit 24.15

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ John S. Watson
 
 
exv24w16
 

Exhibit 24.16

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS:

     WHEREAS, ChevronTexaco Corporation, a Delaware corporation (the “Corporation”), contemplates filing with the Securities and Exchange Commission at Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual Report on Form 10-K.

     WHEREAS, the undersigned is an officer or director, or both, of the Corporation.

     N O W, T H E R E F O R E, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, TERRY MICHAEL KEE, PATRICIA L. TAI, WALKER C. TAYLOR, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do and cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 9th day of March, 2004.

     
 
       /s/ Stephen J. Crowe
 
 

 

exv31w1
 

Exhibit 31.1

RULE 13a-14(a)/15d-14(a) CERTIFICATION

I, David J. O’Reilly, certify that:

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

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

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

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

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

      b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

      c) disclosed in this Annual Report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

      a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial data; and

      b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: March 9, 2004

  /s/ DAVID J. O’REILLY
 
  David J. O’Reilly, Chairman of the Board
  and Chief Executive Officer

E-7

exv31w2
 

Exhibit 31.2

RULE 13a-14(a)/15d-14(a) CERTIFICATION

I, John S. Watson, certify that:

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

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

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

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

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

      b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

      c) disclosed in this Annual Report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected or is reasonably likely to materially affect the registrant’s internal control over financial reporting; and

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

      a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial data; and

      b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: March 9, 2004

  /s/ JOHN S. WATSON
 
  John S. Watson, Vice President, Finance
  and Chief Financial Officer

E-8

exv32w1
 

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Annual Report of ChevronTexaco Corporation (the “Company”) on Form 10-K for the year ended December 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David J. O’Reilly, Chairman and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

      (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

      (2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Dated: March 9, 2004

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

E-9

exv32w2
 

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Annual Report of ChevronTexaco Corporation (the “Company”) on Form 10-K for the year ended December 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John S. Watson, Vice President, Finance, and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

      (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

      (2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Dated: March 9, 2004

  /s/ John S. Watson
 
  John S. Watson, Vice President, Finance
  and Chief Financial Officer

E-10

exv99w1
 

Exhibit 99.1

DEFINITIONS OF SELECTED FINANCIAL TERMS

Return on Average Capital Employed

Net income (adjusted for interest expense and minority interest) divided by average capital employed. Capital employed is stockholders’ equity plus total debt plus capital lease obligations plus minority interests. Average capital employed is computed by averaging the sum of capital employed at the beginning and end of the year.

Return on Average Stockholders’ Equity

Net income divided by average stockholders’ equity. Average stockholders’ equity is computed by averaging the sum of the beginning-of-year and end-of-year balances.

Current Ratio

Current assets divided by current liabilities.

Interest Coverage Ratio

Income before income tax expense, cumulative effect of change in accounting principles and extraordinary items plus interest and debt expense and amortization of capitalized interest divided by before-tax interest costs.

Total Debt to Total Debt-Plus-Equity Ratio

Total debt, including capital lease obligations, divided by total debt plus stockholders’ equity.

E-11