UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
xþ     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year endedDecember 31, 20042005
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
ChevronTexacoChevron Corporation
(Exact name of registrant as specified in its charter)
     
Delaware 94-0890210 6001 Bollinger Canyon Road, San Ramon,
California 9458394583-2324
     
(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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes þ          No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes o          No þ
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 xþ          No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act. (Check one):
Large accelerated filerþ                         Accelerated filero                         Non-accelerated filero
Indicate by check mark whether the registrant is an accelerated filera shell company (as defined in Rule 12b-2 of the Act).     Yes xo          No 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 — $99,547,278,421$115,713,269,274 (As of June 30, 2004)2005)
Number of Shares of Common Stock outstanding as of February 25, 200523, 2006 — 2,104,440,2782,226,159,801
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 20052006 Annual Meeting and 20052006 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 20052006 Annual Meeting of Stockholders (in Part III)

TABLE OF CONTENTS
             
ItemItem Page No.Item Page No.
     
PART I PART I PART I
1.  Business  3 1.  Business  3 
   (a) General Development of Business  3    (a) General Development of Business  3 
   (b) Description of Business and Properties  5    (b) Description of Business and Properties  4 
        Capital and Exploratory Expenditures  6        Capital and Exploratory Expenditures  5 
        Petroleum — Exploration and Production  6        Petroleum — Exploration and Production  5 
        Net Production of Crude Oil and Natural Gas Liquids and Natural Gas  7        Net Production of Crude Oil and Natural Gas Liquids and Natural Gas  6 
        Acreage  8        Average Sales Prices and Production Costs per Unit of Production  7 
        Reserves  9        Gross and Net Productive Wells  7 
        Contract Obligations  9        Reserves  8 
        Development Activities  10        Acreage  8 
        Exploration Activities  10        Contract Obligations  8 
        Review of Ongoing Exploration and Production Activities in Key Areas  11        Development Activities  9 
        Petroleum — Sale of Natural Gas and Natural Gas Liquids  21        Exploration Activities  10 
        Petroleum — Refining Operations  22        Review of Ongoing Exploration and Production Activities in Key Areas  10 
        Petroleum — Sale of Refined Products  23        Petroleum — Sale of Natural Gas and Natural Gas Liquids  24 
        Petroleum — Transportation  24        Petroleum — Refining Operations  24 
        Chemicals  25        Petroleum — Sale of Refined Products  25 
        Coal  26        Petroleum — Transportation  27 
        Synthetic Crude Oil  26        Chemicals  28 
        Global Power Generation  26        Coal and Other Minerals  29 
        Gas-to-Liquids  26        Synthetic Crude Oil  29 
        Research and Technology  26        Global Power Generation  30 
        Environmental Protection  27        Gas-to-Liquids  30 
        Website Access to SEC Reports  27        Chevron Energy Solutions  30 
2.  Properties  28        Research and Technology  30 
3.  Legal Proceedings  28        Environmental Protection  30 
4.  Submission of Matters to a Vote of Security Holders  28        Web Site Access to SEC Reports  31 
1A. 1A.  Risk Factors  31 
1B. 1B.  Unresolved Staff Comments  32 
2. 2.  Properties  32 
3. 3.  Legal Proceedings  32 
4. 4.  Submission of Matters to a Vote of Security Holders  32 
   Executive Officers of the Registrant at March 1, 2005  29    Executive Officers of the Registrant at March 1, 2006  33 
PART II PART II PART II
5. 5.  Market for the Registrant’s Common Equity, Related Stockholder Matters and   Issuer Purchases of Equity Securities  35 
6. 6.  Selected Financial Data  35 
7. 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations  35 
7A. 7A.  Quantitative and Qualitative Disclosures About Market Risk  35 
8. 8.  Financial Statements and Supplementary Data  36 
9. 9.  Changes in and Disagreements with Auditors on Accounting and Financial Disclosure  36 
9A. 9A.  Controls and Procedures  36 
5.  Market for the Registrant’s Common Equity, Related Stockholder Matters and   Issuer Purchaser of Equity Securities  31    (a) Evaluation of Disclosure Controls and Procedures  36 
6.  Selected Financial Data  31    (b) Management’s Report on Internal Control Over Financial Reporting  36 
7.  Management’s Discussion and Analysis of Financial Condition and Results   of Operations  31    (c) Changes in Internal Control Over Financial Reporting  36 
7A.  Quantitative and Qualitative Disclosures About Market Risk  31 
8.  Financial Statements and Supplementary Data  32 
9.  Changes in and Disagreements with Auditors on Accounting and Financial   Disclosure  32 
9A.  Controls and Procedures  32 
   (a) Evaluation of Disclosure Controls and Procedures  32 
   (b) Management’s Report on Internal Control Over Financial Reporting  32 
   (c) Changes in Internal Control Over Financial Reporting  32 
9B.  Other Information  32 
9B. 9B.  Other Information  36 
PART III PART III PART III
10. 10.  Directors and Executive Officers of the Registrant  37 
10.  Directors and Executive Officers of the Registrant  33    Other Information  37 
11.  Executive Compensation  33 
12.  Security Ownership of Certain Beneficial Owners and Management  33 
13.  Certain Relationships and Related Transactions  33 
14.  Principal Accounting Fees and Services  34 
11. 11.  Executive Compensation  37 
12. 12.  Security Ownership of Certain Beneficial Owners and Management  37 
13. 13.  Certain Relationships and Related Transactions  38 
14. 14.  Principal Accounting Fees and Services  38 
PART IV PART IV PART IV
15.  Exhibits, Financial Statement Schedules  34 
15. 15.  Exhibits, Financial Statement Schedules  39 
   Schedule II — Valuation and Qualifying Accounts  35    Schedule II — Valuation and Qualifying Accounts  40 
   Signatures  36    Signatures  41 
EXHIBIT 12.1 EXHIBIT 12.1 EXHIBIT 12.1
EXHIBIT 21.1 EXHIBIT 21.1 EXHIBIT 21.1
EXHIBIT 23.1 EXHIBIT 23.1 EXHIBIT 23.1
EXHIBIT 24.1 EXHIBIT 24.1 EXHIBIT 24.1
EXHIBIT 24.2 EXHIBIT 24.2 EXHIBIT 24.2
EXHIBIT 24.3 EXHIBIT 24.3 EXHIBIT 24.3
EXHIBIT 24.4 EXHIBIT 24.4 EXHIBIT 24.4
EXHIBIT 24.5 EXHIBIT 24.5 EXHIBIT 24.5
EXHIBIT 24.6 EXHIBIT 24.6 EXHIBIT 24.6
EXHIBIT 24.7 EXHIBIT 24.7 EXHIBIT 24.7
EXHIBIT 24.8 EXHIBIT 24.8 EXHIBIT 24.8
EXHIBIT 24.9 EXHIBIT 24.9 EXHIBIT 24.9
EXHIBIT 24.10 EXHIBIT 24.10 EXHIBIT 24.10
EXHIBIT 24.11 EXHIBIT 24.11
EXHIBIT 24.12 EXHIBIT 24.12
EXHIBIT 31.1 EXHIBIT 31.1 EXHIBIT 31.1
EXHIBIT 31.2 EXHIBIT 31.2 EXHIBIT 31.2
EXHIBIT 32.1 EXHIBIT 32.1 EXHIBIT 32.1
EXHIBIT 32.2 EXHIBIT 32.2 EXHIBIT 32.2
EXHIBIT 99.1 EXHIBIT 99.1 EXHIBIT 99.1
EXHIBIT 99.2

1

CAUTIONARY STATEMENTSSTATEMENT 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 ChevronTexacoChevron Corporation contains forward-looking statements relating to ChevronTexaco’sChevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “projects,” “believes,” “seeks,” “schedules,” “estimates” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, ChevronTexacoChevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
      Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are unknown or unexpected problems in the resumption of operations affected by Hurricanes Katrina and Rita and other severe weather in the Gulf of Mexico; crude oil and natural gas prices; refining margins and marketing margins; chemicals prices and competitive conditions affecting supply and demand for aromatics, olefins and additives products; actions of competitors; the competitiveness of alternate energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the ability to successfully integrate the operations of Chevron and Unocal Corporation; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction orstart-up of planned projects; the potential disruption or interruption of the company’s net production or manufacturing facilities due to war, accidents, political events, civil unrest or severe weather; the potential liability for remedial actions under existing or future environmental laws or regulations;regulations and litigation; significant investment or product changes under existing or future environmental regulations and litigation (including, particularly, regulations and litigation dealing with gasoline composition and characteristics); the potential liability resulting from pending or future litigation; the company’s acquisition or disposition of assets; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and thosethe factors set forth under the heading “Risk Factors” in Part I, Item 1 of this Annual Report.report. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed hereinin this report could also could have material adverse effects on forward-looking statements.

2

PART I
Item 1.Business
(a)General Development of Business
Summary Description of ChevronTexacoChevron
      ChevronTexacoChevron 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, mining operations of coal mining,and other minerals, power generation and energy services. The company conducts business activities in the United States and approximately 180 other countries. Petroleum operations consist of exploring for, developing and producing crude oil and natural gas; refining crude oil into finished petroleum products; marketing crude oil, natural gas and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipeline, marine vessel, motor equipment and rail car. Chemicals operations include the manufacture and marketing, by affiliates, of commodity petrochemicals for industrial uses, and the manufacture and marketing, by a consolidated subsidiary, of fuel and lubricating oil additives.
      In this report, exploration and production of crude oil, natural gas liquids and natural gas may be referred to as “E&P” or “upstream” activities. Refining, marketing and transportation may be referred to as “RM&T” or “downstream” activities. A list of the company’s major subsidiaries is presented on pagesE-4 andE-5 of this Annual Report on Form 10-K. As of December 31, 2004, ChevronTexaco2005, Chevron had more than 56,00059,000 employees (including about 9,3006,000 service station employees). Approximately 25,000,27,000, or 4546 percent, of the company’s employees were employed in U.S. operations.
Acquisition of Unocal Corporation
      On August 10, 2005, the company acquired Unocal Corporation (Unocal), an independent oil and gas exploration and production company. This acquisition was accounted for under the rules of Financial Accounting Standards Board (FASB) Statement No. 141,“Business Combinations.”Unocal’s principal upstream operations are in North America and Asia, including the Caspian region. Other activities include ownership interests in proprietary and common carrier pipelines, natural gas storage facilities and mining operations. Further discussion of the Unocal acquisition is contained in Note 2 on pageFS-36 of this Annual Report on Form 10-K.
Overview of Petroleum Industry
      Petroleum industry operations and profitability are influenced by many factors, and individual petroleum companies have little control over some of them. Governmental policies, particularly in the areas of taxation, energy and the environment have a significant impact on petroleum activities, regulating where and how companies conduct their operations and formulate their products and, in some cases, limiting their profits directly. Prices for crude oil and natural gas, petroleum products and petrochemicals are determined by supply and demand for these commodities. The members of the Organization of Petroleum Exporting Countries (OPEC) are typically the world’s swing producers of crude oil, and their production levels are a major factor in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and worldwide economies, although weather patterns and taxation relative to other energy sources also play a significant part. Variations in the components of refined products sales due to seasonality are not primary drivers of changes in the company’s overall annual earnings.
      Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. ChevronTexacoChevron competes with fully integrated major petroleum companies as well as independent and national petroleum companies for the acquisition of crude oil and natural gas leases and other properties, and for the equipment and labor required to develop and operate those properties. In its downstream business, ChevronTexaco also competes with fully integrated major petroleum companies and other independent refining and marketing entities in the sale or purchase of various goods or services in many national and international markets.
Operating Environment
      Refer to pages FS-2 through FS-21 of this Annual Report on Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion on the company’s current business environment and outlook.
 
1 Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. On May 9, 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term “ChevronTexaco”“Chevron” and such terms as “the company,” “the corporation,” “our,” “we,”“we” and “us” may refer to ChevronTexacoChevron 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 ChevronTexacoChevron — 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.

3

leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron also competes with fully integrated major petroleum companies and other independent refining, marketing and transportation entities in the sale or acquisition of various goods or services in many national and international markets.
Risk FactorsOperating Environment
      ChevronTexaco isRefer to pages FS-2 throughFS-11 of this Annual Report on Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a major fully integrated petroleum company with a diversified business portfolio, strong balance sheet, and a history of generating sufficient cash to fund capital and exploratory expenditures and to pay dividends. Nevertheless, some inherent risks could materially impactdiscussion on the company’s financial results of operations or financial condition.
ChevronTexaco is exposed to the effects of changing commodity prices.
      ChevronTexaco is primarily in a commoditiescurrent business with a history of price volatility. The single largest variable that affects the company’s results of operations is crude oil prices. Except in the ordinary course of running an integrated petroleum business, ChevronTexaco does not seek to hedge its exposure to price changes. A significant, persistent decline in crude oil prices may have a material adverse effect on its results of operationsenvironment and its capital and exploratory expenditure plans.
The scope of ChevronTexaco’s business will decline if the company does not successfully develop resources.
      The company is in an extractive business; therefore, if ChevronTexaco is not successful in replacing the crude oil and natural gas it produces with good prospects for future production, the company’s business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining rights to explore, develop and produce hydrocarbons in promising areas, drilling success, ability to bring long lead-time, capital intensive projects to completion on budget and schedule, and efficient and profitable operation of mature properties.
The company’s operations could be disrupted by natural or human factors.
      ChevronTexaco operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations and facilities are therefore subject to disruption from either natural or human causes, including hurricanes, earthquakes, floods, civil unrest, fires and explosions, any of which could result in suspension of operations, or harm to people or the natural environment.
ChevronTexaco’s business subjects the company to liability risks.
      The company produces, transports, refines and markets materials with potential toxicity, and it purchases, handles and disposes of other potentially toxic materials in the course of the company’s business. ChevronTexaco operations also produce byproducts, which may be considered pollutants. Any of these activities could result in liability, either as a result of an accidental, unlawful discharge or as a result of new conclusions on the effects of the company’s operations on human health or the environment.
Political instability could harm ChevronTexaco’s business.
      The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates. As has occurred in the past, actions could be taken by host governments to increase public ownership of the company’s partially– or wholly owned businesses, and/or to impose additional taxes or royalties.
      In certain locations, host governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries. Internal unrest, acts of violence or strained relations between a host government and the company or other governments may affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results, and are carefully considered by management when evaluating the level of current and future activity in such countries. At December 31, 2004, approximately 27 percent of the company’s proved reserves were located in Kazakhstan. The company also has significant interests in Organization of Petroleum Exporting Countries (OPEC)-member countries

4

including Indonesia, Nigeria and Venezuela. Approximately 25 percent of the company’s net proved reserves, including affiliates, were located in OPEC countries at December 31, 2004.outlook.
ChevronTexacoChevron Strategic Direction
      ChevronTexaco’sChevron’s primary objective is to create value and achieve sustained financial returns from its operations that will enable it to outperform its competitors. The company set a goal to generate the highest total stockholder return (based on a combination of stock price appreciation and reinvested dividends) among a designated peer group for the five-year period 2000-2004. BP, ExxonMobil and Royal Dutch Shell – among the world’s largest publicly traded integrated petroleum companies – comprised the company’s designated competitor peer group for this purpose. For the five years ending December 31, 2004, ChevronTexaco tied one other company in the peer group for the highest total stockholder return.
As a foundation for attainingachieving this goal,objective, the company had established four key priorities,the following strategies, which continue into 2005:2006:
Strategies for Major Businesses
 •Operational excellenceUpstream —through safe, reliable, efficientgrow profitability in core areas, build new legacy positions and environmentally sound operations.commercialize the company’s natural gas equity resource base by targeting North American and Asian markets
 
 •Cost reductionDownstream —improve returns by lowering unit costs through innovationfocusing on areas of market and technology.
•Capital stewardshipby investing in the best project opportunities and executing them successfully (safer, faster, and at lower cost).
•Profitable growththrough leadership in developing new business opportunities in both existing and new markets.supply strength
Supporting these four priorities is a focus on:Enabling Strategies Companywide
 •Organizational Capability:Invest in people Having the right people, processes and culture to achieve the company’s strategies
•Leverage technologyto deliver superior performance and sustain industry-leadinggrowth
•Build organizational capabilityto deliver world-class performance in the four primary areas described above.operational excellence, cost reduction, capital stewardship and profitable growth
           The company’s long-term strategies for its largest businesses build on this framework and focus on balancing financial returns and growth. The strategies for upstream (exploration and production) are to grow profitability in core areas, build new legacy positions, and commercialize the company’s natural gas equity resource base by targeting North American and Asian markets. The primary strategy for downstream (refining, marketing and transportation) is to continue to improve returns by focusing on areas of market and supply strength.
(b)Description of Business and Properties
      The upstream and downstream activities of the company are widely dispersed geographically. The company hasgeographically, with operations in North America, South America, Europe, Africa, the Middle East, Central and Far East Asia, and Australia. Besides the large upstream and downstream businesses, the company’s other comparatively smaller business segment is chemicals, which is conducted by the company’s 50 percent-owned affiliate –— Chevron Phillips Chemical Company LLC (CPChem) –— and the wholly owned Chevron Oronite Company (Chevron Oronite). CPChem has operations in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar, Mexico and Belgium. Chevron Oronite is a fuel and lubricating-oil additives business that owns and operates facilities in the United States, France, the Netherlands, Singapore, Japan and JapanBrazil and has equity interests in facilities in India and Mexico.
      ChevronTexacoChevron also owns an approximate 2524 percent equity interest in the common stock of Dynegy Inc. (Dynegy), an energya provider engaged in power generation, gatheringof electricity to markets and processing of natural gas, andcustomers throughout the fractionation, storage, transportation and marketing of natural gas liquids.United States. The company holds an additional investment in Dynegy preferred stock. Refer to page FS-11 and Note 8 on page FS-36FS-13 for further information relating to the company’s investment in Dynegy.
      Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2004,2005, and assets as of the end of each year — for the United States and the company’s major international geographic areas — may be found in Note 98 to the consolidated financial statements beginning on page FS-36FS-40 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 1413 and 1514 on pages FS-39FS-44 to FS-41.FS-46.

54

Capital and Exploratory Expenditures
      AExcluding the $17.3 billion acquisition of Unocal Corporation, total reported expenditures for 2005 were $11.1 billion, including $1.7 billion for the company’s share of affiliates’ expenditures, which did not require cash outlays by the company. In 2004 and 2003, expenditures were $8.3 billion and $7.4 billion, respectively, including the company’s share of affiliates’ expenditures of $1.6 billion and $1.1 billion in the corresponding periods.
      Of the $11.1 billion in expenditures for 2005, about three-fourths, or $8.4 billion, related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2004 and 2003. International upstream accounted for about 70 percent of the worldwide upstream investment in each of the years, reflecting the company’s continuing focus on opportunities that are available outside the United States.
      In 2006, the company estimates capital and exploratory expenditures will be 33 percent higher at $14.8 billion, including spending by affiliates. About three-fourths, or $11.3 billion, is again targeted for exploration and production activities, with $8 billion of that amount outside the United States.
      Refer also to a discussion of the company’s capital and exploratory expenditures is contained on pages FS-12FS-14 and FS-13FS-15 of this Annual Report on Form 10-K.
Petroleum — Exploration and Production
      The table on the following tablepage summarizes the company’s and affiliates’ net production of liquids and natural gas production for 20042005 and 2003.2004. As part of the Unocal acquisition in August 2005, Chevron acquired interests in producing operations in Azerbaijan, Bangladesh, Canada, the Democratic Republic of the Congo, Indonesia, Myanmar, the Netherlands, Thailand and the United States. In September 2005, the producing operations in Canada were sold.

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Net Production1 of Crude Oil and Natural Gas Liquids and Natural Gas
                          
  Crude Oil & Natural Gas   Memo: Oil-Equivalent
  Liquids (Thousands of Natural Gas (Millions of (BOE) (Thousands of
  Barrels per Day) Cubic Feet per Day) Barrels per Day)2
       
  2004 2003 2004 2003 2004 2003
             
United States:
                        
 California  221   231   108   112   239   250 
 Gulf of Mexico  154   189   815   1,059   290   365 
 Texas  62   84   382   463   125   161 
 Wyoming  10   10   166   179   38   40 
 Other States  58   48   402   415   125   117 
                   
Total United States  505   562   1,873   2,228   817   933 
                   
Africa:
                        
 Angola  140   154   26   —   144   154 
 Chad  37   8   —   —   37   8 
 Nigeria  119   123   59   50   129   131 
 Republic of Congo  12   13   —   —   12   13 
 
Democratic Republic of the Congo3
  4   9   —   —   4   9 
Asia-Pacific:
                        
 
Partitioned Neutral Zone (PNZ)4
  117   134   20   15   120   136 
 Australia  43   48   305   284   93   95 
 China  18   23   —   —   18   23 
 Kazakhstan  31   25   125   101   52   42 
 Thailand  20   25   93   104   35   42 
 Philippines  7   8   131   140   28   31 
 
Papua New Guinea5
  —   4   —   —   —   4 
Indonesia
  215   223   149   166   240   251 
Other International:
                        
 United Kingdom  106   116   340   378   163   179 
 Canada  62   73   51   110   71   91 
 Argentina  45   52   64   74   56   65 
 Denmark  46   42   130   99   68   59 
 Norway  11   10   2   —   11   10 
 Venezuela  5   5   34   21   11   9 
 Colombia  —   —   210   206   35   35 
 Trinidad and Tobago  —   —   135   116   23   19 
                   
Total International  1,038   1,095   1,874   1,864   1,350   1,406 
                   
Total Consolidated Operations  1,543   1,657   3,747   4,092   2,167   2,339 
 
Equity Affiliates6
  167   151   211   200   202   184 
                   
Total Including Affiliates7,8
  1,710   1,808   3,958   4,292   2,369   2,523 
                   
                          
  Crude Oil & Natural Gas   Memo: Oil-Equivalent
  Liquids (Thousands of Natural Gas (Millions of (Thousands of
  Barrels per Day) Cubic Feet per Day) Barrels per Day)2
       
  2005 2004 2005 2004 2005 2004
             
United States:
                        
 California  217   221   106   108   235   239 
 
Gulf of Mexico3
  112   154   579   815   208   290 
 
Texas3
  61   62   380   382   124   125 
 Wyoming  9   10   161   166   36   38 
 
Other States3
  56   58   408   402   124   125 
                   
Total United States3
  455   505   1,634   1,873   727   817 
                   
Africa:
                        
 Angola  139   140   36   26   145   144 
 Nigeria  125   119   68   59   136   129 
 Chad  38   37   3   —   39   37 
 Republic of the Congo  11   12   8   —   12   12 
 
Democratic Republic of the Congo3,4
  1   4   —   —   1   4 
Asia-Pacific:
                        
 
Partitioned Neutral Zone (PNZ)5
  112   117   22   20   116   120 
 
Thailand3
  43   20   409   93   111   35 
 Australia  42   43   362   305   102   93 
 Kazakhstan  37   31   142   125   61   52 
 China  26   18   —   —   26   18 
 
Azerbaijan3
  13   —   1   —   13   — 
 Philippines  8   7   163   131   35   28 
 
Bangladesh3
  —   —   59   —   10   — 
 
Myanmar3
  —   —   32   —   5   — 
Indonesia3
  202   215   211   149   237   240 
Other International:
                        
 United Kingdom  83   106   300   340   133   163 
 
Canada3
  54   62   19   51   57   71 
 Denmark  47   46   146   130   71   68 
 Argentina  43   45   55   64   52   56 
 Norway  8   11   2   2   9   11 
 Venezuela  4   5   35   34   10   11 
 
Netherlands3
  2   —   4   —   3   — 
 Colombia  —   —   185   210   31   35 
 Trinidad and Tobago  —   —   115   135   19   23 
                   
Total International3
  1,038   1,038   2,377   1,874   1,434   1,350 
                   
Total Consolidated Operations3
  1,493   1,543   4,011   3,747   2,161   2,167 
 
Equity Affiliates6
  176   167   222   211   213   202 
                   
Total Including Affiliates3,7,8
  1,669   1,710   4,233   3,958   2,374   2,369 
                   
 1Net production excludes royalty interests owned by others.
 2Barrels of oil-equivalent (BOE) is crude oil and natural gas liquids plus natural gas converted to oil-equivalent gas (OEG) barrels at 6 MCF6,000 cubic feet = 1 OEG barrel.
 3The companyIncludes net production of the former Unocal properties from August 1, 2005.
4Chevron sold its interest in the Democratic Republic of the Congo in mid-2004.mid-2004 but acquired another interest as a result of the Unocal merger.
 45Located between the Kingdom of Saudi Arabia and the State of Kuwait.
 5The company sold its interest in Papua New Guinea and resigned operatorship of the Kutubu, Gobe and Moran oil fields in 2003.
6Represents Chevron’s share of production by affiliates. Affiliates include Tengizchevroil (TCO) in Kazakhstan and Hamaca in Venezuela.
 7Includes natural gas consumed on lease of 343380 and 333343 million cubic feet per day in 20042005 and 2003,2004, respectively.
 8Does not include other produced volumes:
                      
Athabasca Oil Sands – net  27  15  —  —  27  15 
Athabasca Oil Sands — net  32  27  —  —  32  27 
Boscan Operating Service Agreement  113  99  —  —  113  99   111  113  —  —  111  113 

76

In 2004, ChevronTexaco2005, Chevron conducted its exploration and production operations in the United States and approximately 2535 other countries. Worldwide oil-equivalent production of approximately 2.5 million barrels per day in 2004,2005, including volumes produced from oil sands in Canada and production under an operating service agreement declined approximately 5 percent from 2003. The declinein Venezuela, was largelyabout the result of lower productionsame as in 2004. Production in the United Stateslast five months of 2005 included volumes associated with the properties acquired from Unocal. However, production during the year from the heritage-Chevron properties declined from their levels in 2004, due mainly to normal field declines, property sales and curtailmentsoperations that were offline as a result of damages to producing operations fromAugust and September hurricanes in the Gulf of Mexico, in September 2004. International oil-equivalent production was down marginallyproperty sales between years.periods, the effect of higher prices on volumes required under cost-recovery and variable-royalty provisions of certain contracts, and normal field declines. Refer to the “Results of Operations” section beginning on page FS-6FS-7 for a detailed discussion of the factors explaining the 2002-20042003 — 2005 changes in production for crude oil and natural gas liquids and natural gas.
      ForThe company estimates that its average oil-equivalent production in 2006 will be in the past six years,range of 2.7 to 2.8 million barrels per day. The additional volumes over the company’s2.5 million barrels per day produced in 2005 are attributable mainly to the properties acquired from Unocal and new projectstart-ups that are expected to help offset normal field declines in existing operations. However, the company cautions that any future estimate of production is subject to many uncertainties, including quotas that may be imposed by OPEC, the price effect on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, the rate of recovery of production being restored in the Gulf of Mexico following the 2005 hurricanes, and production that may have to be shut in due to weather conditions, civil unrest, changing geopolitics or other disruptions to daily operations. Expected additions to production capacity in 2007 through 2009 may permit worldwide oil-equivalent production including the volumes produced from oil sands and production under an operating service agreement, has followed a downward trend. Production in 2004 was 85 percent of 1998 levels equivalent to an average annual decline rate of about 3 percent. For 2005, the company again expects worldwide oil-equivalent production to be lower. Increases internationally in 2005 are not expected to fully offset lower rates in the United States, which the company projects will result largely from normal field declines and the absence of production associated with property sales. The actual level of worldwide production in 2005 remains uncertain for reasons including the potential for constraints imposed by OPEC, and disruptions caused by weather, local civil unrest and other factors. Production capacity in the 2006-2008 period may permit the worldwide oil-equivalent production level to increase from that expectedlevels in 2005.2006. Refer to the “Review of Ongoing Exploration and Production Activities in Key Areas”Areas,” beginning on page 1110, for a discussion of the company’s major oil and gas development projects.
Average Sales Prices and Production Costs per Unit of Production
      Refer to Table IV on page FS-70 of this Annual Report on Form 10-K for data about the company’s average sales price per unit of crude oil and natural gas produced as well as the average production cost per unit for 2005, 2004 and 2003.
Gross and Net Productive Wells
      The following table summarizes gross and net productive wells at year-end 2005 for the company and its affiliates:
Productive Oil and Gas Wells1 at December 31, 2005
                  
  Productive2 Productive2
  Oil Wells Gas Wells
     
  Gross Net Gross Net
         
United States:                
 California  24,899   22,804   285   80 
 Gulf of Mexico  2,874   2,085   1,793   1,333 
 Other U.S.   24,947   9,248   10,684   4,953 
             
Total United States  52,720   34,137   12,762   6,366 
             
Africa  2,520   723   10   4 
Asia-Pacific  2,846   1,430   1,703   1,072 
Indonesia  7,986   7,843   186   148 
Other International  1,700   895   295   115 
             
Total International  15,052   10,891   2,194   1,339 
             
Total Consolidated Companies  67,772   45,028   14,956   7,705 
Equity in Affiliates  522   182   —   — 
             
Total Including Affiliates  68,294   45,210   14,956   7,705 
             
Multiple completion wells included above:  656   404   248   172 
1Includes 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.
2Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned and the sum of the company’s fractional interests in gross wells.

7

Reserves
      Table V, beginning on page FS-70, provides a tabulation of the company’s proved net oil and gas reserves, by geographic area, as of each year-end 2003 through 2005 and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period. During 2005, the company provided oil and gas reserves estimates for 2004 to the Department of Energy, Energy Information Agency. Such estimates are consistent with, and do not differ more than 5 percent from, the information furnished to the SEC on the company’s Annual Report on Form 10-K. During 2006, the company will file estimates of oil and gas reserves with the Department of Energy, Energy Information Agency, consistent with the reserve data reported in Table V.
Acreage
      At December 31, 2004,2005, 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, 20042005
(Thousands of Acres)
                                                  
         Developed          Developed
     and      and
 Undeveloped2 Developed2 Undeveloped  Undeveloped2 Developed2 Undeveloped
             
 Gross Net Gross Net Gross Net  Gross Net Gross Net Gross Net
                         
United States:United States:                   United States:                   
California  112  91  189  171  301  262 California  146  125  204  172  350  297 
Gulf of Mexico  3,782  2,780  1,898  1,325  5,680  4,105 Gulf of Mexico  4,726  3,277  2,115  1,425  6,841  4,702 
Other U.S.   3,236  2,628  4,118  2,201  7,354  4,829 Other U.S.   5,023  3,546  5,845  2,664  10,868  6,210 
                           
Total United StatesTotal United States  7,130  5,499  6,205  3,697  13,335  9,196 Total United States  9,895  6,948  8,164  4,261  18,059  11,209 
                           
AfricaAfrica  19,836  7,103  852  252  20,688  7,355 Africa  18,048  6,045  972  289  19,020  6,334 
Asia-PacificAsia-Pacific  22,369  11,511  1,959  632  24,328  12,143 Asia-Pacific  53,585  25,092  2,854  1,294  56,439  26,386 
IndonesiaIndonesia  5,396  3,267  279  267  5,675  3,534 Indonesia  12,678  7,171  388  348  13,066  7,519 
Other InternationalOther International  34,207  18,490  3,046  1,758  37,253  20,248 Other International  32,270  18,290  3,807  2,026  36,077  20,316 
                           
Total InternationalTotal International  81,808  40,371  6,136  2,909  87,944  43,280 Total International  116,581  56,598  8,021  3,957  124,602  60,555 
                           
Total Consolidated CompaniesTotal Consolidated Companies  88,938  45,870  12,341  6,606  101,279  52,476 Total Consolidated Companies  126,476  63,546  16,185  8,218  142,661  71,764 
Equity Affiliates  1,022  485  129  58  1,151  543 
Equity in AffiliatesEquity in Affiliates  863  407  136  60  999  467 
                           
Total Including AffiliatesTotal Including Affiliates  89,960  46,355  12,470  6,664  102,430  53,019 Total Including Affiliates  127,339  63,953  16,321  8,278  143,660  72,231 
                           
 1Gross 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.
 2Developed acreage is spaced or assignable to productive wells. Undeveloped acreage is acreage where wells have not been drilled or completed to permit commercial production and that may contain undeveloped proved reserves. The gross undeveloped acres that will expire in 2005, 2006, 2007 and 20072008 if production is not established by certain required dates are 10,573, 7,0625,130, 9,774 and 3,374,7,681, respectively.

8

Refer to Table IV on page FS-62 of this Annual Report on Form 10-K for data about the company’s average sales price per unit of oil and gas produced, as well as the average production cost per unit for 2004, 2003 and 2002. The following table summarizes gross and net productive wells at year-end 2004 for the company and its affiliates.
Productive Oil and Gas Wells at December 31, 2004
                  
  Productive1 Productive1
  Oil Wells Gas Wells
     
  Gross2 Net2 Gross2 Net2
         
United States:                
 California  22,892   21,363   178   54 
 Gulf of Mexico  1,895   1,609   1,060   841 
 Other U.S.   19,772   6,298   10,029   4,838 
             
Total United States  44,559   29,270   11,267   5,733 
             
Africa  1,707   601   7   3 
Asia-Pacific  1,985   960   213   88 
Indonesia  7,035   6,980   81   69 
Other International  1,426   906   233   97 
             
Total International  12,153   9,447   534   257 
             
Total Consolidated Companies  56,712   38,717   11,801   5,990 
Equity Affiliates  370   123   —   — 
             
Total Including Affiliates  57,082   38,840   11,801   5,990 
             
Multiple completion wells included above:  924   615   552   413 
1Includes 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.
2Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned and the sum of the company’s fractional interests in gross wells.
Reserves
      Table V, beginning on page FS-63, sets forth the company’s proved net oil and gas reserves, by geographic area, as of December 31, 2004, 2003 and 2002. Also, refer to Table V for a discussion of major changes to proved reserves by geographic area for 2004. During 2004, the company provided oil and gas reserves estimates for 2003 to the Department of Energy, Energy Information Agency. Such estimates are consistent with and do not differ more than 5 percent from the information furnished to the SEC in this Annual Report on Form 10-K. During 2005, the company will file estimates of oil and gas reserves with the Department of Energy, Energy Information Agency, consistent with the reserve data reported in Table V.
Contract Obligations
      The company sells crude oil natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. Most contracts generally commit the company to sell quantities based on production from specified properties, but certain natural gas sales contracts specify delivery of fixed and determinable quantities.
      In the United States, the company is contractually committed to deliver to third parties and affiliates approximately 180195 billion cubic feet of natural gas through 20072008 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.

98

      Outside the United States, the company is contractually committed to deliver to third parties a total of approximately 700780 billion cubic feet of natural gas from 2006 through 20072008 from Australian, Canadian, ColombianAustralia, Canada, Colombia and Philippine reserves.the Philippines. 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, Colombianreserves in Australia, Colombia and Philippine reserves.the Philippines. The company plans to meet its Canadian contractual delivery commitments through third-party purchases.
Development Activities
      Details of the company’s development expenditures and costs of proved property acquisitions for 2005, 2004 2003 and 20022003 are presented in Table I on page FS-58.FS-65 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, 2004.2005. A “development well” is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. “Wells drilling” includes wells for which drilling activities have been temporarily suspended.interrupted at the end of 2005.
Development Well Activity
                                                           
   Net Wells Completed1    Net Wells Completed1
 Wells    Wells  
 Drilling at        Drilling at      
 12/31/04 2004 2003 2002  12/31/052 20053 2004 2003
                 
 Gross2 Net2 Prod. Dry Prod. Dry Prod. Dry  Gross Net Prod. Dry Prod. Dry Prod. Dry
                                 
United States                         
United States:United States:                         
California  –  –  636  1  418  –  227  1 California  —  —  661  —  636  1  418  — 
Gulf of Mexico  2  1  43  3  47  6  78  4 Gulf of Mexico  5  4  29  3  43  3  47  6 
Other U.S.   18  8  221  3  232  12  333  11 Other U.S.   53  30  256  4  221  3  232  12 
                                   
Total United StatesTotal United States  20  9  900  7  697  18  638  16 Total United States  58  34  946  7  900  7  697  18 
                                   
AfricaAfrica  6  2  36  –  24  –  27  – Africa  4  1  38  —  36  —  24  — 
Asia-PacificAsia-Pacific  46  8  84  –  43  –  44  – Asia-Pacific  39  15  156  —  84  —  43  — 
IndonesiaIndonesia  –  –  163  –  562  –  426  – Indonesia  —  —  107  —  163  —  562  — 
Other InternationalOther International  7  1  84  –  107  –  140  – Other International  28  8  96  —  84  —  107  — 
                                   
Total InternationalTotal International  59  11  367  –  736  –  637  – Total International  71  24  397  —  367  —  736  — 
                                   
Total Consolidated CompaniesTotal Consolidated Companies  79  20  1,267  7  1,433  18  1,275  16 Total Consolidated Companies  129  58  1,343  7  1,267  7  1,433  18 
Equity Affiliates  4  2  20  –  18  –  20  – 
Equity in AffiliatesEquity in Affiliates  8  3  23  —  20  —  18  — 
                                   
Total Including AffiliatesTotal Including Affiliates  83  22  1,287  7  1,451  18  1,295  16 Total Including Affiliates  137  61  1,366  7  1,287  7  1,451  18 
                                   
 1Indicates the fractional number of wells completed during the year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency.
 2Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned and the sum of the company’s fractional interests in gross wells.
3Includes completion of wells from August 1, 2005, related to the former Unocal operations.

9

Exploration Activities
      The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the last three years and the number of exploratory wells drilling at December 31, 2004.2005. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unproved areas and include delineation wells, which are wells drilled to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend a known reservoir beyond the proved area.

10

“Wells drilling” includes wells for which drilling activities have been temporarily suspended. Refer tointerrupted at the suspended wells discussion in “Litigation and Other Contingencies” in Management’s Discussion and Analysisend of Financial Condition and Results of Operations on page FS-17 and Note 1, Summary of Significant Accounting Policies; “Properties, Plant and Equipment” on pages FS-30 and FS-31 and Note  21, Accounting for Suspended Exploratory Well Costs beginning on page FS-45 for further discussion.2005.
      The ultimate disposition of these well costs is dependent on one or more of the following: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory drilling that is under way or firmly planned, and (3) securing final regulatory approvals for development.
Exploratory Well Activity
                                                          
   Net Wells Completed1    Net Wells Completed1
 Wells    Wells  
 Drilling        Drilling      
 at 12/31/04 2004 2003 2002  at 12/31/052 20053 2004 2003
                 
 Gross2 Net2 Prod. Dry Prod. Dry Prod. Dry  Gross Net Prod. Dry Prod. Dry Prod. Dry
                                 
United States:United States:                         United States:                         
California  –  –  –  –  –  –  –  – California  —  —  —  —  —  —  —  — 
Gulf of Mexico  19  10  13  8  25  9  44  10 Gulf of Mexico  10  6  14  8  13  8  25  9 
Other U.S.   –  –  3  1  2  1  13  12 Other U.S.   3  2  5  6  3  1  2  1 
                                   
Total United StatesTotal United States  19  10  16  9  27  10  57  22 Total United States  13  8  19  14  16  9  27  10 
                                   
AfricaAfrica  –  –  3  1  3  1  6  1 Africa  1  —  4  1  3  1  3  1 
Asia-PacificAsia-Pacific  1  1  16  –  6  3  4  – Asia-Pacific  16  —  10  —  16  —  6  3 
IndonesiaIndonesia  –  –  2  –  1  –  –  1 Indonesia  —  —  5  —  2  —  1  — 
Other InternationalOther International  5  3  3  7  2  4  7  9 Other International  7  1  15  4  3  7  2  4 
                                   
Total InternationalTotal International  6  4  24  8  12  8  17  11 Total International  24  1  34  5  24  8  12  8 
                                   
Total Consolidated CompaniesTotal Consolidated Companies  25  14  40  17  39  18  74  33 Total Consolidated Companies  37  9  53  19  40  17  39  18 
Equity Affiliates  –  –  –  –  –  –  4  – 
Equity in AffiliatesEquity in Affiliates  —  —  7  —  —  —  —  — 
                                   
Total Including AffiliatesTotal Including Affiliates  25  14  40  17  39  18  78  33 Total Including Affiliates  37  9  60  19  40  17  39  18 
                                   
 1Indicates the fractional number of wells completed during the year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency.
Some exploratory wells are not drilled with the intention of producing from the well bore. In such cases, “completion” refers to the completion of drilling. Further categorization of productive or dry is based on the determination as to whether hydrocarbons in a sufficient quantity were found to justify completion as a producing well, whether or not the well is actually going to be completed as a producer.
 2Represents wells that are in the process of drilling but have been neither abandoned nor completed as of the last day of the year. Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned and the sum of the company’s fractional interests in gross wells.
3Includes completion of wells from August 1, 2005, related to the former Unocal operations.
     Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2005, 2004 2003 and 20022003 are presented in Table I on page FS-58.FS-65 of this Annual Report on Form 10-K.
Review of Ongoing Exploration and Production Activities in Key Areas
      ChevronTexaco’s 2004Chevron’s 2005 key upstream activities, also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations beginning on page FS-2, are presented below. The comments below include referencereferences to “total production” and “net production,” which excludes partner shares and royalty interests. “Total production” includes these components.are defined in Exhibit 99.1 on page E-11 of this Annual Report on Form 10-K. Certain annual production statistics include volumes from the former Unocal operations from August 1, 2005. In addition to the activities discussed, ChevronTexacoChevron was active in other geographic areas, but thesethose activities were less significant.
      The discussion below also references the status of proved reserves recognition for significant long-lead-time projects not yet on production and for projects recently placed on production. Reserves are not discussed for recent discoveries notthat have yet advancedto advance to a project stage and for production in mature areas.

1110

Consolidated Operations
 
a)United States
      The United States upstream activities are concentrated in the Gulf of Mexico, California, Louisiana, Texas, New Mexico, and the Rocky Mountains.Mountains and California. Average daily net production during 20042005 was approximately 505,000455,000 barrels of liquids and 1.91.6 billion cubic feet of natural gas, or 817,000727,000 barrels per day on an oil-equivalent basis. TheWith the acquisition of Unocal in August 2005, the company announced plans in 2003 to sell interests in nonstrategic producingobtained properties that complemented and enhanced Chevron’s already-strong positions in the United States,Gulf of Mexico and during 2004 substantially all of the larger asset packages were sold. The effect of these sales on 2004 net oil-equivalent production was about 30,000 barrels per day. The remaining properties earmarked for sale are expected to be disposed of during 2005Permian Basin in West Texas and represent less than 1 percent of the U.S. oil-equivalent production at the end of 2004.New Mexico. Refer to Table V beginning on page FS-63FS-70 for a discussion of the reserves and different characteristics for the company’s major U.S. producing areas.
   
 

California: The company has significant production in the San Joaquin Valley. In 2004,2005, average daily net production was 217,000212,000 barrels of crude oil, 108106 million cubic feet of natural gas and 4,0005,000 barrels of natural gas liquids, or 239,000235,000 barrels of daily net production on an oil-equivalent basis. Approximately 8483 percent of the crude oil production is considered heavy oil (typically with API gravity lower than 22 degrees).
   
 Gulf of Mexico: CombiningAverage daily net production rates during 2005 for the company’s interestcombined interests in the Gulf of Mexico shelf and deepwater areas and on-shorethe fields onshore Louisiana average daily net production rates during 2004 were 138,000101,000 barrels of crude oil, 815579 million cubic feet of natural gas and 16,00011,000 barrels of natural gas liquids, or approximately 290,000208,000 oil-equivalent barrels daily.

In deepwater, Prior to the company has an interesthurricanes in three significant producing fields: Genesis, PetroniusAugust and Typhoon. Petronius, 50 percent-owned and operated, maintainedSeptember, oil-equivalent production in the Gulf of Mexico averaged approximately 300,000 barrels per day. Because of storm damages, fourth quarter 2005 production averaged only 160,000 barrels per day. The expected production level for the full year 2006 is about 200,000 barrels per day, with a dailyslightly higher rate occurring in the first half of the year. Approximately 20,000 net production of 14,000oil-equivalent barrels of crude oil and 25 million cubic feet of natural gas in 2004.daily production are not expected to be sufficiently economic to restore.

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      In the deepwater areas, the company has an interest in four producing fields: Genesis, Petronius, K2 and Mad Dog. K2 and Mad Dog were added to the portfolio as a result of the Unocal acquisition.
      The 57 percent-owned and operated Genesis Field averaged daily net production of approximately 13,0009,000 barrels of crude oil and 1811 million cubic feet of natural gas in 2004.2005, or 11,000 barrels of oil-equivalent.
      Petronius, which is 50 percent-owned and operated, had daily net production of 14,000 barrels of crude oil and 17 million cubic feet of natural gas in 2005, or 17,000 barrels of oil-equivalent. Petronius production was shut-inshut in for repairs following hurricane damage in September 2004 and is expected to resume producingresumed production in March 2005. Typhoon,
      The Perseus discovery, which is 50 percent-owned and operated, hadpart of the Petronius development, began production from its first well in the second quarter 2005. Fromstart-up through year-end, average daily net production of approximately 11,000was 3,000 barrels of crude oil and natural gas liquids and 14 million cubic feet of natural gas in 2004, including production from the Boris Field that utilizes the Typhoon production facility.
      Development continues on the company-operated Perseus and Tahiti projects, which are not yet on production. The company’s ownership interests are 50 percent and 58 percent, respectively. At Perseus, platform rig damage due to the September 2004 hurricane delayed the estimated completion of the first producing well until April 2005.oil-equivalent. A second productionextended-reach well is scheduledexpected to follow in the first quarter 2006. Average netbegin production in 2005 from the first Perseus well through the Petronius facilities is estimated at more than 4,000 netApril 2006, with anticipated daily production rates between 3,000 and 7,000 barrels of oil-equivalent per day after start-up. The initial booking of proved undeveloped reserves occurred in 2003 and a reclassification of certain reserves to proved developed will occur in early 2005, prior to the start of production from the first well.net oil-equivalent. The Perseus project has an estimated production life of between six to nine years, with maximum production anticipated in 2006. The company anticipates the majority of proved undeveloped reserves will be categorized as proved developed by the end of 2006.
      Chevron has a 13 percent nonoperated interest in the former Unocal K2 Field, which had initial production from its first well in May 2005 and nineincreased to approximately 2,000 barrels of net oil-equivalent production per day by November.
      Chevron holds a 16 percent nonoperated interest in the Mad Dog Field, which commenced production in early 2005 and had average daily net production of 4,000 barrels of oil-equivalent for the five months following the acquisition of Unocal. Development work continues in order to increase the daily maximum total production to the design capacity of 80,000 barrels of crude oil and 40 million cubic feet of natural gas and is expected to be complete in 2008. Additional studies are under way to expand the total crude oil production capacity to more than 100,000 barrels per day. The Mad Dog Field has an estimated production life of 20 years. Additional reserve reclassification to proved developed is expected to coincide with the development program through 2008.
At Tahiti, engineering and equipment procurement wasTyphoon, the tension leg platform suffered catastrophic damage from Hurricane Rita in process during 2004. A successful well testSeptember 2005. Teams were formed to investigate the cause of the original discovery well was also conductedincident and evaluate options to possibly restore operations. Average daily net production prior to the storm from the 50 percent-owned and operated Typhoon Field, along with volumes processed from the nearby 25 percent-owned and nonoperated Boris Field, averaged about 6,000 barrels of oil-equivalent per day. Typhoon and Boris production remained shut-in in 2004.early 2006 pending ongoing salvage and restoration studies.
      Development activity continues on the 58 percent-owned and operated Tahiti Field, where productionstart-up is expected in 2008. Most contracts for the engineering, procurement, fabrication and installation of the spar hull, topsides and subsea equipment were awarded in 2005. Construction of the floating production facility began in the fourth quarter. Initial booking of proved undeveloped reserves occurred in 2003, and the transfer of certainthese reserves into the proved developed category is anticipated upon productionstart-up. With an expected production life of 30 years, Tahiti is anticipated to have a maximum total daily production of 125,000 barrels of crude oil and 70 million cubic feet of natural gas.
      At the 63 percent-owned and operated Blind Faith discovery, a subsea development utilizing a semi-submersible production system was approved by Chevron and its partner in late 2005, at which time the company made its initial booking of proved undeveloped reserves. Reclassification of these reserves to the proved developed category is anticipated in the first half 2008, when first production is scheduledexpected. Initial total daily output is estimated at 30,000 barrels of crude oil and 30 million cubic feet of natural gas.
      Chevron also continues to begin. Tahiti is expectedevaluate development of the 33 percent-owned and nonoperated Great White discovery. Successful appraisal drilling was conducted in 2004, and the partners have formed a project management team to have a production lifebegin front-end engineering and design (FEED) in March 2006. No proved reserves had been recognized for this discovery as of 25 years.early 2006.
      InThe company participated in five wells in the Gulf of Mexico deepwater exploration program during 2005. The 2005 program resulted in two announced discoveries and one successful appraisal well. The discoveries were the company participated in 11 deepwater exploratory wells during 200425 percent-owned and announced two discoveries —nonoperated Knotty Head discovery and the 5060 percent-owned and operated Jack prospect andBig Foot prospect. Additional appraisal activity was ongoing at both locations in early 2006. At the 1730 percent-owned and nonoperated Tobago prospect. Further

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Tubular Bells prospect that was discovered in 2003, further evaluation of commercial potential also continued, on the 2003 discovery at the 30 percent-owned and nonoperated Tubular Bells prospect with additionalfollow-up drilling planned for 2006. A successful appraisal well was drilled in 2005 at the 2005-to-2006 timeframe. Commercial2004 Jack discovery. An extended production test is expected to be under way in March 2006. Evaluation continues at nearby Saint Malo, where a successfulfollow-up appraisal workwell was drilled during 2004. The first appraisal well also continuescommenced drilling at the nonoperated 33 percent-owned Great White Field, including an additional2003 Puma discovery; however, the well that is planned in 2005,was not completed as of early 2006 due to extensive weather and at the nonoperated 13 percent-owned Saint Malo discovery.rig-related delays. Proved reserves havewere not beenyet recognized for any of these projects. Appraisal drilling also occurred in 2004 at the 63 percent-owned and operated Blind Faith. Initial production is expected byprospects as of early 2008. No proved reserves have been recognized for this project. The 75 percent-owned and operated Tonga prospect was drilled in 2003 and the data from this well is under evaluation.2006.
      In December 2004,Besides the company announced it had finalizedactivities connected with the development and exploration projects in the Gulf of Mexico area, Chevron also filed an application with the Federal Energy Regulatory Commission in the third quarter 2005 to own, construct and operate a 20-year agreement for regasification capacitynatural gas import terminal at Casotte Landing in Jackson County, Mississippi. The proposed project, to be located adjacent to the proposed Sabine PassChevron-owned Pascagoula Refinery, would be designed to process imported liquefied natural gas (LNG) terminal. In November 2004,for distribution to industrial, commercial and residential customers in Mississippi and the Southeast region, including the growing Florida market. The terminal would have an initial natural-gas processing capacity of 1.3 billion cubic feet per day.
      The company also exercised an option to increase its capacity at the Sabine Pass LNG terminal to 1 billion cubic feet per day. Additionally in the Sabine Pass area, the company announced it had planssigned an agreement in mid-2005 to submit federalsecure 1 billion cubic feet per day of pipeline capacity in a new pipeline that will be connected to the Sabine Pass LNG terminal. Interconnect capacity of 600 million cubic feet per day was also secured to an existing pipeline. The new pipeline is planned to be in service in 2009, coinciding with the company’s Sabine Pass terminal commitments. The new pipeline system will provide access to Chevron’s Sabine and state permit applicationsBridgeline pipelines, which connect to the Henry Hub. The Henry Hub is the pricing point for a regasification terminalnatural gas futures contracts traded on the New York Mercantile Exchange (NYMEX) and is located on the natural gas pipeline system in Louisiana. Henry Hub interconnects to import LNG located at its Pascagoula Refinery.nine interstate and four intrastate pipelines.
     Other U.S. Areas: Outside of California and the Gulf of Mexico, the company manages operations in areas of the midcontinent United States extendingthat extend from the Rockies to southern Texas. In 2004, averageThe acquisition of Unocal in 2005 added to production operations in the Permian Basin of western Texas and southeastern New Mexico, the San Juan Basin area of New Mexico and Colorado, and in East Texas. Also as a result of the Unocal acquisition, Chevron operates 10 offshore platforms in Alaska and five producing natural gas fields in the Cook Inlet and owns nonoperated production on the North Slope. During 2005, the company’s operations outside California and the Gulf of Mexico averaged daily net production was 130,000of 126,000 barrels of crude oil and natural gas liquids and 950949 million cubic feet of natural gas.gas (284,000 barrels of oil-equivalent).

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b)Africa
   
 Angola: ChevronTexacoChevron is the largest producer of crude oil and liquefied petroleum gasesoperator in Angola. The company was the first to produce in the deepwater. Cabinda Gulf Oil Company Limited (CABGOC), a wholly owned subsidiary of ChevronTexaco, is operator of two concessions, Block 0 and Block 14 concessions off the west coast, of Angola, north of the Congo River. Block 0, in which CABGOCChevron has a 39 percent interest, is a 2,155-square-mile concession adjacent to the Cabinda coastline. Block 14, in which CABGOCChevron has a 31 percent interest, is a 1,580-square-mile deepwater concession located west of Block 0.

In Block 0, the company operates in two areas –— A and B –— composed of 1920 fields producing 116,000that produced 119,000 barrels per day of net liquids in 2004.2005. Area A, comprising 1314 producing fields, averaged daily net daily production of approximately 78,00073,000 barrels of crude oil and 1,000 barrels of liquefied petroleum gas (LPG) in 2004.2005. Area B which is now the combination of areas previously known as Area B and Area C, has six producing fields and averaged daily net production of 37,00043,000 barrels of crude oil and 2,000 barrels of LPG in 2004. In 2004,2005. Included in the company finalized a 20-year extension of its Block 0 concession, which will expire in 2030. TheArea B production was the Sanha condensate natural gas utilization and Bomboco crude oil project, located in Area B, began operations with the installation of facilities and the start ofwhich started production in late 2004.2004 and averaged daily net production of 10,000 barrels of oil-equivalent in 2005.

The Block 0 concession extends through 2030. Initial recognition of proved reserves for the Sanha Bomboco project was made at the end of 2002. Initial reclassification of reserves from proved undeveloped to proved developed occurred in 2004 and willis expected to continue during the drilling program that is scheduled for completion in 2005 and 2006.2007.

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      In Block 14, net production in 2004 from the Kuito Field, Angola’s first deepwater producing area, averaged approximately 18,00015,000 net barrels of crude oil per day. The development plansday in 2005. First oil was produced from the Belize Field in January 2006. This was the initial production from Phase 1 of the $2.3 billion integrated drilling and production project for the Benguela, Belize, Lobito and Tomboco fields. Proved undeveloped reserves for both Benguela and Belize were recognized in 1998, and certain volumes for Belize were transferred to proved developed in 2005. The concession period for these fields expires in 2027.
      Phase 2 of the Block 14 were approved in 2003. Phase 1 of the $2.2 billion projectdevelopment involves the installation of an integrated drilling andsubsea production platform and the development of the Benguela and Belize fields, projected for first oil in early 2006. Proved undeveloped reserves for these fields were booked in 1998. Phase 2 involves the installation of subsea systems, pipelines and wells for Lobito and Tomboco. Proved undeveloped reserves for these fields were bookedrecognized in 2000. Phase 2 is under construction, with first oil planned forin late 2006. After both phases are completed, maximum total daily production in 2008 is estimated at more thanapproximately 200,000 barrels per day of crude oil in 2008. Some provedoil. Proved developed reserves willare expected to be recognized near to the time of first oil.oil once certain project milestones have been met. The concession period for these fields will expireexpires in 2027.
      The Tombua and Landana and Tombua fields in Block 14 were discovered in 1997 and 2001, respectively, and appraisal drilling was doneconducted from 1998 through 2002. Proved undeveloped reserves for Tombua and Landana were bookedrecognized in 2001 and 2002, respectively. Feasibility studies were completed in 2004 for theThe Tombua-Landana development which is targeted as the next major capital project for Block 14, and is currentlywith FEED having begun in front-end engineering.2005. Estimated capital expenditures for the development exceed $2 billion. Proved developed reserves will start to be recognized near the time of first production.The concession period expires in 2028.
      ChevronTexacoChevron also has two other concessions in Angola.Angola — Block 2, 20 percent-owned and operated, and Blockthe joint venture FST area, in which the company has a 16 percent nonoperated interest. Net production from these properties in 2005 totaled 5,000 barrels of crude oil per day. Sonangol, Angola’s national oil company, is scheduled to become operator of Block 2 during 2006.
      In addition to the producing activities in Angola, the company also has a 36 percent interest hadin the planned Angola LNG project, which will be integrated with natural gas production in the area. In April 2005, the project partners awarded FEED contracts for a combined5-million-metric-ton-per-year onshore LNG plant in the northern part of the country. Chevron and Sonangol are co-leaders of the project. Construction is expected to begin in 2007. Proved natural gas reserves associated with this project have not yet been recognized.
Democratic Republic of the Congo: As a result of the Unocal acquisition, Chevron acquired an 18 percent nonoperated working interest in a production-sharing contract off the coast of the Democratic Republic of the Congo. Daily net production for the five months after the Unocal acquisition from the seven acquired fields averaged 2,000 barrels of nearly 6,000crude oil.
Republic of the Congo: Chevron has a 32 percent interest within the Haute Mer area (Nkossa, Nsoko and Moho-Bilondo exploitation permits) and a 29 percent interest within the Marine VII area (Kitina and Sounda exploitation permits), all of which are offshore Republic of the Congo and adjacent to the company’s concessions in Angola. Net production from the Republic of the Congo properties averaged 11,000 barrels of crude oil per day in 2004.2005. The Moho and Bilondo satellite field development was approved in 2005, with first production expected in 2008. Proved undeveloped reserves were initially recognized in 2001. Transfer to the proved developed category is expected near the time of first production. The Moho-Bilondo concession expires in 2030.
     Southern Africa:The Angola LNG Project is an integrated gas utilization project. ChevronTexacoLianzi-2 appraisal well was drilled in 2005 to assess the size and Sonangol,commerciality of the state oil companysuccessfulLianzi-1 well drilled in the 14K/A-IMI Unit, located in a joint development area shared between the Republic of Angola, are co-leading the projectCongo and Angola, in which the company hasis operator and holds a 3631 percent interest. Front-end engineering and design work is expected to start in the first halfNo proved reserves had been recognized as of 2005.early 2006.
     Chad-Cameroon: ChevronTexacoChevron is a non-operatingnonoperating partner in a project to develop crude oil fields in southern Chad and transport crude oil by pipeline to the coast of Cameroon for export. NetAverage daily net production from three fields in 20042005 was 37,00038,000 barrels of crude oil. All three of the original fields are now on production. Proved undeveloped reserves were bookedrecorded in 2000 and began to bemost have been reclassified to proved developed reserves. Over the next three to four years, additional reserves will be transferred to the proved developed category as additional wells are drilled, facilities are expanded and reservoir pressure-support projects are in 2002. The productionplace. Production began in 2003, and the life of the fieldfields is estimated at 30 years.

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ChevronTexaco Chevron has a 25 percent interest in the upstream operations and an approximatea 21 percent interest in the pipeline.
Equatorial Guinea: ChevronTexaco is a 45 percent partner and operator of the L Block offshore the Republic of Equatorial Guinea. The first exploration well, Ballena-1, was completed in 2003. In the fourth quarter 2004, ChevronTexaco initiated partial farm-out activities and, if completed, plans to drill two stratigraphic prospects in Block L.
     Libya: In early 2005, the company was awarded Block 177 in Libya’s first exploration license round under the Exploration and Production Sharing Agreement IV. The company was also made operator ofChevron will operate Block 177 with a 100 percent equity.equity interest. A work program is under way, and contracting for the acquisition of seismic data is scheduled to begin in 2006.

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 Equatorial Guinea: Chevron is a 22 percent partner and operator of the Block L offshore Equatorial Guinea. The first exploration well completed in 2003 was non-commercial. A partner joined the venture in 2005 in return for partially funding an additional exploratory well to be drilled in 2006.

Nigeria: ChevronTexaco’sChevron’s principal subsidiary in Nigeria, Chevron Nigeria Limited (CNL), operates and holds a 40 percent interest in 1114 concessions, predominantly in the onshore and near-offshore regions of the Niger Delta. CNL operates under a joint-venture arrangement with the Nigerian National Petroleum Corporation (NNPC), which owns the remaining 60 percent interest. ChevronTexaco’s subsidiaries Chevron Oil Company Nigeria Limited (COCNL) and Texaco Overseas Nigeria Petroleum Company Unlimited (TOPCON) each hold a 20 percent interest in six additional concessions. TOPCON operates these concessions under a joint venture agreement with NNPC, which owns the remaining 60 percent interest. Effective November 2004, all the rights, duties, obligations, assets and liabilities of TOPCON and COCNL were merged into CNL.

In 2004,2005, daily net production from the 38 operated32 fields averaged 117,000122,000 barrels of crude oil, 2,0003,000 barrels of LPG and 5968 million cubic feet of natural gas. Certain onshore operations in the western Niger Delta were suspended in March 2003 as a result of community disturbance.
      Net onshoreOnshore operations in the Niger Delta with a net production capacity of aboutapproximately 45,000 barrels of crude oil per day, has been shut-in since March 2003. The company has adoptedincluding the Olero Creek development, were suspended in 2003 as a phased plan to restore these operations and has taken initial steps to determineresult of the extent of damage and secure the properties. The company has begun initial production-resumption efforts in certain areas.ongoing civil unrest. The Abiteye Field, closest to the Escravos terminal, was returned to production in 2004. Repairs to the Makaraba Flow Station were completed in mid-2005, allowing for the resumption of production of 6,000 net barrels per day from the Abiteye, Makaraba and Utonana fields and the Eastern Region. Further restoration of select Dibi wells and flowlines in late 2005 contributed to an additional 6,500 net barrels per day from the Dibi Field. As of year-end 2005, approximately 13,000 of the 45,000 barrels per day had been returned to production. Restoration activities in the remaining fields will continue at least through 2006.
      In May 2004, ChevronTexaco received a 100 percent contractor interest under a production-sharing contract arrangement in OPL (Oil Prospecting License)-247. This agreement further increasedDuring 2005, the company’s leading acreage position in the Nigerian deepwater trend.
      The company also continued development activities infor the deepwater Agbami development. Significant progress was made toward achieving final governmental approvals and executing key agreements. During 2004,project. The company’s share of capital investment for the company drilled four development wells.full project is estimated at $3.4 billion. In early 2005, the Agbami Development hadproject achieved the following major milestones: conversion of OPL-216Oil Prospecting License (OPL) 216 and OPL-217OPL 217 to Oil Mining Lease (OML) 127 and OML (Oil Mining Lease)-127 and OML-128,128; approval of the Field Development Plan,field development plan; award of the contract for the floating production, storage and offloading (FPSO) vessel; execution of the unit (FPSO) contract, concurrence onagreement; award of the Unit Agreementsubsea equipment, subsea installation and offloading system contracts; and approval of initial project funding approval by the partners. Five development wells were drilled in 2005, and development drilling is scheduled to continue through 2009. Proved undeveloped reserves were recognized for this project in 2002. Prior to the anticipated productionstart-up in 2008, certain proved undeveloped reserves wouldare expected to be reclassified to proved developed reserves. The expected field life is approximately 20 years. ChevronTexaco’s shareMaximum total daily production of contractor’s250,000 barrels of liquids is expected to be reached within six to 12 months followingstart-up. Chevron’s ownership interest under the Agbami production-sharing contract arrangements are 80 percent in OML-127 and approximately 46 percent in OML-128.unit agreement is 68 percent.
      In AugustFor the 2003 the Aparo discovery on OPL-213 was extended withOPL 213, Chevron signed a delineation well on OPL-249. The Aparo/ Bonga SW fields straddle OPL-212, OPL-213 and OPL-249. ChevronTexaco signed anjoint-study agreement in 2004 with the operator of OPL-212 in 2004OPL 212 to conduct technical studies in pursuit of a unitized joint development of the Aparo/Aparo and Bonga SW fields, which straddle OPL 212, OPL 213 and OPL 249. Unitization discussions continued through 2005, and a pre-unit agreement is expected to be signed by the end of the first quarter 2006. Development will likely involve an FPSO and subsea wells. FEED and basic engineering are expected to commence by the end of the first quarter 2006. Chevron’s initial interest in the unitized field is anticipated to be 20 percent. Proved undeveloped reserves are expected to be recognized in 2006, and productionstart-up is targeted for late 2010.
      Chevron operates and holds a 95 percent interest in the OPL 249 Nsiko discovery. The timingdiscovery well was drilled in 2003, followed by two successful appraisal wells in 2004. Subsurface evaluations and field development planning continued in 2005. FEED and basic engineering are expected to commence in late 2006.
      In OPL 222 during 2005, activities continued in the greater Usan area with the successful drilling of recognition of proved undeveloped reserves will depend on the completion of these studiesseventh and subsequenteighth appraisal wells. The Usan field-development plan was approved in 2005, and in early 2006, regulatory

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unitization. Also on Block OPL-249, which containsapproval of the 2003 Nsiko discovery, two additional appraisal wells were drilled in 2004. Both wells confirmed the presence of producible crude oil over the entire structure.
      OPL-222 activities continued in 2004 with the appraisal programOML conversion for the greater Usan area and successful drillingdevelopment was in the process of being finalized. Once approved, the end date of the fifth and sixth wells.concession period will be determined. Proved undeveloped reserves were recorded in 2004 for the Usan Field, withand development planned to enter theentered its basic engineering phase in 2005. Initial productionProductionstart-up is estimated to occur in 2009for late 2010, before which time certain proved undeveloped reserves wouldare expected to be reclassified to the proved developed reserves.category. The company holds a 30 percent nonoperated interest in this project.project.
      The Nnwa Field, discovered in OPL 218 in 1999, extends into adjacent blocks OPL 219 and OPL 246. Commerciality of the field is under evaluation. During 2005, OPL 218 was converted to OML 129.
      At the Escravos Gas ProjectPlant (EGP), onshore and offshore engineering, procurement and construction bids were receivedawarded in 2003. Bids were reissued in 2004 following a reviewearly 2005 for the Phase 3 expansion of the project designnatural gas processing facilities. Early site work began in late 2005, and scope. construction commenced in February 2006.Start-up is expected in 2008 and includes adding a second natural gas plant with 395 million cubic feet of capacity, which would increasepotentially increasing capacity to 680 million cubic feet of natural gas per day and increase LPG and condensate exports to 43,000 barrels per day. ChevronTexaco holds a 40 percent interest in this project.
      The company is also pursuing a planned gas-to-liquids facility at Escravos. Lump-sum engineering, procurement and construction bids for the planned gas-to-liquids facility at Escravos were opened in May 2004. Construction is expected to begin during 2005, pending finalization of fiscal terms. The project is the first to use the technology and operational expertise of the Sasol Chevron global 50-50 joint venture. Project start-up is expected in 2008. Proved undeveloped reserves associated with EGP Phase 3 were recognized in 2002. These reserves willare expected to be reclassified to proved developed reserves as various stages of EGP and related projects are completed. The anticipated life of the project is 25 years. Chevron holds a 40 percent operated interest in this project.
      Refer to page 30 for a discussion on the planned Escravosgas-to-liquids facility.
      The West African Gas Pipeline regional project is planned to supply Nigerian natural gas to customers in Ghana, Benin and Togo for industrial applications and power generation. Chevron holds a 38 percent interest in the project. Detailed engineering and the award of several major construction contracts occurred in early 2005. In the third quarter 2005, the company commenced installation of a350-mile main offshore segment of the West African Gas Pipeline that will connect to an existing onshore pipeline in Nigeria.Start-up is expected in late 2006. Chevron is the managing sponsor in West African Pipeline Company Limited, which will construct, own and operate the pipeline.
      The South Offshore Water Injection Project (SOWIP) is an enhancedcrude-oil recovery project in the south offshore area of OML 90. Chevron holds a 40 percent interest as part of the joint venture with NNPC. The objective of the SOWIP is to increase production by providing water injection, natural gas lift and production de-bottlenecking in the South Offshore Asset Area (Okan and Delta fields). Offshore construction and commissioning activities were under way in early 2006. Incremental proved reserves were recognized for SOWIP in 2005. The project has an expected25-year life.
      In November 2004,April 2005, Chevron entered into a memorandum of understanding (MOU) with partners to evaluate the company and its partners inviability of an LNG plant at the Brass LNG ProjectOlokola site located in Nigeria’s central Niger Delta, awardeda free trade zone between Lagos and Escravos. The plans for the contract for front-end engineering and designproposed LNG plant, in which Chevron anticipates holding a 19 percent interest, include a phased development of its two-train liquefied natural gas facility.four processing trains (5.5 million metric tons per year each). FEED is expected to commence by the end of the first quarter 2006. The project is expected to start up in 2010.2010 or 2011. CNL is expected to supply approximately 1.8 billion cubic feet per day of natural gas to the project. CNL is in the process of completing the certification of the reserves required to satisfy the natural gas supply requirements for this project. No proved reserves havehad been recognized for this project.
      Inas of early 2005, the company announced plans to conduct a feasibility study on a potential LNG project at Olokola in southwest Nigeria. Future decisions to move forward with Olokola LNG will depend on the results of the feasibility study.2006.
     Nigeria - São Tomé ande Príncipe Joint Development Zone (JDZ): The company was awarded JDZ Block 1 in 2004. In early 2005, the company signed a production sharingproduction-sharing contract with the Joint Development Authority, under which ChevronTexacoChevron will be the operator with a 51 percent interest.
Republic The first exploration well began drilling in January 2006, with planned completion of Congo: ChevronTexaco has a 30 percent interestdrilling operations in Nkossa, Nsoko and Moho-Bilondo exploitation permits and a 29 percent interest in the Marine VII Kitina and Sounda exploitation permits, all of which are offshore Republic of Congo and adjacent to the company’s concessions in Angola. Net production from the company’s concessions in the Republic of Congo averaged 12,000 barrels of crude oil per day in 2004. Assessment of the Moho and Bilondo satellite fields progressed during 2004, with the drilling of the MOBIM 1 well. Work is in progress to determine the development plan for the field.
Southern Africa: Appraisal drilling is planned in 2005 to assess the size and commerciality of the successful Lianzi-1 well drilled in the 14K/A-IMI Unit, located between the Republic of Congo and Angola, in which the company is operator and holds an approximate 31 percent interest. Timing is uncertain regarding the recognition of proved reserves.March 2006.

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c)Asia-Pacific
   
 Australia: ChevronTexacoChevron has a 17 percent interest in the North West Shelf (NWS) Projectventure offshore Western Australia. Daily net production from the project during 20042005 averaged 17,000 barrels of condensate, 305360 million cubic feet of natural gas, 15,00014,000 barrels of crude oil and 4,0005,000 barrels of liquefied petroleum gas. Approximately 7074 percent of the natural gas was sold primarily under long-term contracts, in the form of LNG to major utilities in Japan and South Korea.Korea, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market. The Train 4 LNG expansion project completed during 2004 increased LNG capacity approximately 50 percent and encompassed the installationExpansion of a second 80-mile pipeline fromfifth LNG train, which will increase export capacity by more than 4 million metric tons per year to approximately 16 million, was approved in 2005, with commissioning expected in 2008. In December 2005, the offshoreventure participants approved development of the Angel natural gas fieldsfield, which will supply the fifth LNG train. NWS reserves are recorded according to onshore facilities.existing sales agreements. Start-up of the fifth LNG train will accelerate reclassification of proved undeveloped reserves to proved developed. The first LNGend of Train 4 was produced in September 2004. A ninth LNG carrier, operated by Chevron Transport Corporation Ltd., was added to the NWS-controlled fleet. In December,concession period for the China Guangdong LNG sales purchase agreement became unconditional and the equity agreement with China National Offshore Oil Corporation (CNOOC) was completed.NWS project is 2034.
      ChevronTexacoOn Barrow and Thevenard islands, Chevron operates the crude oil producing facilities on Barrow and Thevenard Islands, whichthat had combined net crude oil production of 7,0006,000 barrels per day in 2004. ChevronTexaco2005. Chevron’s equity interest in this operation is 57 percent for Barrow Island and 51 percent for Thevenard Island.
      ChevronTexacoChevron also is the operator of the 57 percent-owned Gorgon-area fields and has between 50 to 100 percent interestinterests in other Greater Gorgon fields off the northwest coast of Australia. The 12Twelve discovered natural gas fields straddle 17 lease blocks in the Greater Gorgon Area. Chevron and its two joint-venture participants signed a Framework Agreement in April 2005 that will enable the combined development of Gorgon and the nearby natural gas fields as one world-scale project. Chevron has a 50 percent ownership interest across most of the Greater Gorgon Area. The Gorgon Project is moving forwardawarded upstream and downstream FEED and engineering, procurement and construction contracts in June 2005 for a two-train (10 million metric tons per year) LNG facility and a possible domestic natural gas plant on front-end-engineering-and-design feasibility work,Barrow Island, targeting initial production for 2009-2010. Preliminary gas sales agreements have been signed with CNOOC and with a planned North American West Coast terminal.by 2010. Proved reserves have not been recognized for any of the Gorgon fields and reserves bookingGorgon-area fields. Recognition is contingent on securing sufficient LNG sales and purchase agreements and other key project milestones.
      In 2004,the fourth quarter 2005, the company drilledsigned separate nonbinding Heads of Agreements with three companies in Japan to supply LNG from the successful wholly owned Wheatstone-1 natural gas well locatedGorgon project. Negotiations are under way to finalize binding sales agreements. Purchases will range from 1.2 million metric tons per year to 1.5 million metric tons per year of LNG over 25 years, commencing in 2010 and 2011.
      During 2005 and early 2006, the company was awarded exploration rights to five deepwater blocks in the Carnarvon Basin offshore Western Australia. Production testsChevron holds a 50 percent, operated interest in the blocks. Two-dimensional(2-D) seismic survey was acquired over four of the blocks.
      Also in 2005,3-D seismic survey was acquired for the wholly ownedWheatstone-1 2004 natural gas discovery offshore Western Australia. Two appraisal wells were also completed in 2004 and the company is conducting a 3-D seismic program.
Cambodia: ChevronTexaco operates and holds a 55 percent interest in Block A,Browse Basin, located offshore Cambodianorthwest Australia.
      Interests ranging from 25 percent to 50 percent in three blocks offshore southern Australia and two blocks in northwest Australia were added to Chevron’s portfolio through the Gulf of Thailand, after a 15 percent farm-out during 2004. The concession covers approximately 1.6 million acres. ChevronTexaco processed more than 600,000 acres of 3-D seismic data and drilled four exploration wells on the second exploration campaign resulting in four crude oil discoveries in 2004.Unocal acquisition. The company is evaluating appraisal and additional exploration opportunities for 2005. Proved reserves have not been recognized for this project.
China: ChevronTexaco hasworking with partners on a 33 percent interestsdetailed technical evaluation of the blocks in Blocks 16/08 and 16/09, locatedsouthern Australia. The blocks in the Pearl River Delta Mouth Basin. Daily net productionnorthwest have well commitments that are targeted for drilling in 2004 from the eight fields in these blocks averaged about 10,000 barrels of crude oil. The company has a 25 percent interest in QHD-32-6 in Bohai Bay, which had 2004 average net production of about 7,000 barrels of crude oil per day, and a 16 percent working interest in Bozhong 25-1 unitized development project in Block 11/19, located in Bohai Bay, which achieved initial production in August 2004. Average net production from the field was about 1,000 barrels of crude oil per day. The company has interest ranging from 64 to 100 percent interest in five prospective natural gas blocks totaling about 2.7 million acres.next three years.

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 Kazakhstan:Azerbaijan: ChevronTexaco holds a 20Chevron acquired Unocal’s 10 percent working interest in the KarachaganakAzerbaijan International Operating Company (AIOC), which holds offshore crude oil reserves in the Caspian Sea from the Azeri-Chirag-Gunashli (ACG) project. Also as a result of acquiring Unocal, the company has a 9 percent equity interest in Baku-Tbilisi-Ceyhan (BTC) pipeline, which will transport AIOC production from Baku, Azerbaijan through Georgia to deepwater port facilities in Ceyhan, Turkey. The pipeline is planned to have a crude capacity of 1 million barrels per day. The first tanker-loading of crude oil at the Ceyhan marine terminal is expected to occur in the spring of 2006.

In June 2004,the five months of 2005 following the company’s first Karachaganakacquisition of Unocal, AIOC’s daily net crude oil was loaded at Russia’s Black Sea port at Novorossiysk. Phase 2 of the field development, which included construction of gas injection and liquids processing facilities and an increase in liquids export capacity via the company’s 15 percent-owned Caspian Pipeline Consortium (CPC) was completed in the third quarter 2004. Access for Karachaganak production to CPC’s pipeline allows sales of approximately 150,000 barrels per day of processed liquids (28,000 net barrels) to prices available in world markets. During 2004, Karachaganak net daily production averaged 31,000 barrelsbarrels. First oil production from Phase I development of liquidsthe ACG crude oil project began in early 2005, and 125 million cubic feetproduction from the first of natural gas.two additional platforms in Phase II began at the end of 2005, at which time a portion of proved undeveloped reserves were reclassified to proved developed. Production from the second platform is expected in late 2006. Phase III, which is the deepwater portion of the project and the final phase of development, was approved in 2004. Production start-up for Phase III is targeted for 2008. Proved undeveloped reserves will be reclassified to proved developed reserves associated with Phase 2 have been added over the 2002-to-2004 timeframe.as new wells are drilled and completed. The KarachaganakAIOC operations are conducted under a 40-year concession agreement30-year production-sharing contract that expires in 2038.at the end of 2024.
     Partitioned Neutral Zone (PNZ):Kazakhstan: Saudi Arabian Texaco Inc., a ChevronTexaco affiliate,Chevron holds a 60-year concession, originally signed in 1949, to produce onshore crude oil from the PNZ, located between the Kingdom of Saudi Arabia and the State of Kuwait. The Kingdom of Saudi Arabia and the State of Kuwait each own an undivided 5020 percent nonoperated interest in the PNZ’s hydrocarbon resources. The company, by virtueKarachaganak project that is being developed in phases. Phase 2 of its concession, has the rightsfield development was completed in 2004, and Phase 3 was under evaluation as of early 2006. Access for Karachaganak production to the Kingdom’s undivided 50 percent interestCaspian Pipeline Consortium (CPC) pipeline allows sales of approximately 150,000 barrels per day of processed liquids (28,000 net barrels) at prices available in the hydrocarbon resources located in the onshore PNZ and pays a royalty and other taxes on hydrocarbons produced.world markets. During 2004, average2005, Karachaganak daily net production was 117,000averaged 37,000 barrels of crude oilliquids and 20142 million cubic feet of natural gas. Proved developed reserves associated with Phase 2 were added in 2002 through 2005. The Karachaganak operations are conducted under a40-year concession agreement that expires in 2038. Timing for the recognition of Phase 3 reserves and an increase in production are uncertain and depend on achieving a natural gas sales agreement. Refer also to page 23 for a discussion of Tengizchevroil, a 50 percent-owned affiliate with operations in Kazakhstan.
     Philippines:Russia: TheIn 2005, OAO Gazprom included Chevron on a list of companies that could continue further commercial and technical discussions concerning the development and related commercial activities of the Shtokmanovskoye Field. Discussions were under way in early 2006, but the timing of Gazprom’s selection of the company holdsor companies that will participate in the field development was uncertain. Shtokmanovskoye is a 45very large natural gas field offshore Russia in the Barents Sea. OAO Gazprom is Russia’s largest natural gas producer.
Turkey and Georgia: Chevron is the operator of the Silopi Block in southeast Turkey with a 25 percent interest. It also has a 25 percent interest in Turkey Black Sea deepwater Block 3534, which was part of the Malampaya natural gas field located about 50 miles offshore Palawan Island. Malampaya representsUnocal acquisition. Also as part of the first offshoreUnocal acquisition, Chevron holds 10 percent interests in several adjacent blocks in Georgia.
Bangladesh: Through the Unocal acquisition, Chevron became operator of four blocks, with a 98 percent interest in Blocks 12, 13 and 14 and a 43 percent interest in Block 7. For the five-month period after the acquisition, the properties averaged daily net production of natural gas in the Philippines. Daily net production was 131141 million cubic feet of natural gas. In early 2006, Chevron was supplying about 20 percent of the natural gas market in Bangladesh. Chevron plans to build a natural gas processing plant and 7,000 barrels of condensate.natural gas pipeline in connection with a 2004 agreement to produce natural gas from the Bibiyana Field in Block 12. Initial production is expected late in the fourth quarter 2006. Additional proved reserves are expected to be recorded in 2006. The Bibiyana production-sharing contract expires in 2034. First production from the Moulavi Bazar Field began in March 2005. The Moulavi Bazar production-sharing contract expires in 2028.

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Cambodia: Chevron operates and holds a 55 percent interest in the 1.6 million-acre Block A, located offshore in the Gulf of Thailand. In 2004, the company processed more than 600,000 acres of 3-D seismic data and drilled five exploration wells in its second exploration campaign, resulting in four crude oil discoveries. As a result, Chevron and its partners in 2005 obtained a two-year extension of the Cambodia exploration permit. As of early 2006, the company was evaluating data from the five wells and was planning a third drilling campaign that is expected to begin later in the year and be completed in 2007.
     Qatar:Myanmar: In 2004, SasolAs a result of the Unocal acquisition, Chevron ChevronTexaco’s 50-50 global joint venture with Sasolhas a 28 percent nonoperated working interest in a production-sharing contract for the production of South Africa, entered intonatural gas from the Yadana Field, located offshore Myanmar in the Andaman Sea. The company also has a memorandum of understanding with Qatar Petroleum28 percent ownership interest in a pipeline company that transports the natural gas from the Yadana Field to expand the Oryx gas-to-liquids project and a letter of intentMyanmar-Thailand border for final delivery to examine GTL base oils opportunitiespower plants in Qatar. Qatar Petroleum and Sasol Chevron also agreed to pursue an opportunity to develop a 130,000 barrels-per-day integrated gas-to-liquids project.Thailand. Average net natural gas production following the acquisition was 76 million cubic feet per day.
     Thailand: ChevronTexacoChevron operates Blocks B8/32, 9A and G4/43 in the Gulf of Thailand. The company holds approximately a 52 percent interest in Blocks B8/32 and 9A and a 60 percent interest in Block G4/43. TheThrough the Unocal acquisition, the company also has operated interests ranging from 35 percent to 80 percent in Blocks 10 through 13 and 12/27 and a 16 percent nonoperated interest in Blocks 14A, 15A and 16A, known collectively as the Arthit Field. Chevron also holds aboth operated and nonoperated interests ranging from 33 percent intereststo 80 percent in a number of exploration Blocks 7, 8 and 9, whichblocks that are currently inactive, pending resolution of border issues between Thailand and Cambodia.
      Block B8/32 produces crude oil and natural gas from four fields: Benchamas, Maliwan, North Jamjuree and Tantawan. Block 9A was brought online in 2005. Daily net production in 20042005 from these fieldstwo blocks was 93105 million cubic feet of natural gas and 20,00025,000 barrels of crude oil. DuringAlso in 2005, the year, 72company completed the development study for the Block 8/32 Central Belt Area, with first production anticipated in 2007.
      Two appraisal wells were drilled in Block G4/43 in early 2005 and five wellheadresulted in the successful extension of the Similan and Lanta oil trends. In addition,3-D seismic data acquisition and processing relating to other prospects were completed in August 2005. First crude oil production is anticipated in early 2007.
      In the acquired Unocal operations, three platforms were installed in Block B8/32. In 2004, the companyPailin and Kaphong areas and 90 wells were drilled post-merger. De-bottlenecking of several central processing platforms was nearly completed an upgradein 2005, which is expected to add more than 150 million cubic feet per day of natural gas processing capacity atcapability. Thai Oil Phase 2 development of the Benchamasoffshore crude oil project in the Pattani Field increasing total capacitystarted up in May 2005. Chevron has the right to approximately 65,000operate in this concession until 2022. Phase 1 development of the Arthit Field began in late 2005, with first production planned for 2007. Net production from these areas for the last five months of 2005 averaged 726 million cubic feet per day of natural gas and 43,000 barrels of crude oil and condensate per day (34,000 net barrels). Further developmentday.
Vietnam: As a result of the concession focused onUnocal acquisition, the North and Central Benchamas Area andcompany has two production-sharing contracts offshore southwest Vietnam in the developmentnorthern part of the North Jarmjuree Field,Malay Basin. Chevron has a 42 percent interest in Blocks B and 48/95 and a 43 percent interest in Block 52/97. In 2005, the company was awarded a 50 percent interest and will be the operator in Block 122, located between the Benchamasoffshore eastern Vietnam.
China: Chevron has a 33 percent nonoperated interest in Blocks 16/08 and Tantawan fields. First production at North Jarmjuree was16/19, located in the third quarter 2004.
      In 2004, the company farmed-outPearl River Delta Mouth Basin; a 25 percent interest inQHD-32-6 in Bohai Bay; and a 16 percent working interest in the unitized and producing Bozhong 25-1 Field in Bohai Bay Block G4/43, reducing its interest11/19. Daily net production from the company’s interests in China averaged 26,000 barrels of crude oil in 2005. The company also has interests ranging from 50 percent to 60 percent. One exploration well and one appraisal well were drilled successfully. Environmental surveys, impact assessments for drilling and 3-D seismic survey acquisition for the first 600,000 acres were completed64 percent in 2004.four prospective onshore natural gas blocks totaling about 1.6 million acres.

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Partitioned Neutral Zone (PNZ): Saudi Arabian Texaco Inc., a Chevron subsidiary, holds a60-year concession that expires in 2009 to produce crude oil from onshore properties in the PNZ, which is located between the Kingdom of Saudi Arabia and the State of Kuwait. As of early 2006, the company was actively seeking an extension or renewal of the agreement. The company, by virtue of its concession, has the right to Saudi Arabia’s 50 percent undivided interest in the hydrocarbon resource and pays a royalty and other taxes on volumes produced. During 2005, average daily net production was 112,000 barrels of crude oil and 22 million cubic feet of natural gas. Construction of steamflood pilot facilities was completed in 2005. The facilities serve as a precursor for a second-phase pilot project that was in the front-end engineering stage in early 2006. The second phase entails drilling 16 injection wells, 25 producing wells and the installation of water-treatment and steam-generation facilities. The estimated total project cost is more than $300 million. This is the first project of its type in the Middle East.
Philippines: The company holds a 45 percent nonoperated interest in the Malampaya natural gas field located about 50 miles offshore Palawan Island. Daily net production in 2005 was 163 million cubic feet of natural gas and 8,000 barrels of condensate. As a result of the Unocal acquisition, Chevron also develops and produces steam resources under an agreement with the National Power Corporation, a Philippine government-owned company. The combined installed generating capacity is 634 megawatts.
d)Indonesia
   
 ChevronTexaco’sChevron’s operated interests in Indonesia are primarily managed by two wholly owned subsidiaries, P.T. CaltexPT. Chevron Pacific Indonesia (CPI) and ChevronTexaco EnergyChevron Geothermal Indonesia (CTEI)(CGI). CPI accounts for nearly half of Indonesia’s total crude oil output and holds an interest inoperates four production-sharing contracts. CTEIcontracts (PSCs), with interests ranging from 50 percent to 100 percent. CGI is a power generation company that operates the Darajat geothermal contract area in West Java with a total capacity of 145 megawatts and a cogeneration facility in support of CPI’s operation in North Duri. In addition to the above interests, ChevronTexacoChevron also has a 25 percent interest in a nonoperated interestjoint venture in South Natuna Sea Block B.

ChevronTexaco’s share Through the Unocal acquisition, the company operates the Salak geothermal field located in West Java, with a total capacity of net production during 2004 was 222,000 barrels of oil-equivalent per day377 megawatts, and holds interests in CPI-operated areas. The Duri Fieldeight PSCs offshore East Kalimantan in the Rokan Block, under steamflood since 1985, is the largest steamflood project in the world, with net production averaging 120,000 barrels of crude oil per day in 2004. ChevronTexaco’s net productionKutei Basin and three PSCs offshore northeast Kalimantan. These interests range from South Natuna Sea Block B in 2004 was about 18,000 barrels of oil-equivalent per day.24 percent to 100 percent.
      A development concept for the Sadewa project, located in the Kutei Basin, is scheduled for selection in 2006, with initial proved reserves recognition planned for 2007. First production is expected in 2008. The company also advanced development plans during 2005 for its Gendalo Hub and Gehem Hub deepwater natural gas projects, also located in the Kutei Basin. Development concepts are expected to be selected in 2006. These projects will likely be developed in parallel, with first production for both projects targeted for the 2010 to 2012 time frame. The actual timing is partially dependent on government approvals and market conditions. In addition, development is progressing on steamflood activity in North Duri.
      Heritage-Chevron’s share of net production in CPI-operated areas during 2005 was 193,000 barrels of oil-equivalent per day. Daily net production from South Natuna Sea Block B in 2005 averaged 21,000 barrels of oil-equivalent. Net production from the acquired Unocal operations was 56,000 barrels of oil-equivalent per day for five months ended December 31, 2005.

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e)Other International Areas
Argentina: Chevron operates in Argentina through its subsidiary, Chevron San Jorge S.R.L. The company and its partners hold more than 2.8 million acres in the Neuquen and Austral basins in 17 operated production concessions and five exploration blocks (one operated and four nonoperated). Working interests range from approximately 19 percent to 100 percent in operated license areas. Exploration farm-out agreements were reached in three blocks during 2005, and farm-out efforts in the remaining two exploration blocks continued into 2006. Daily net production in 2005 averaged 43,000 barrels of crude oil and 55 million cubic feet of natural gas.

Brazil:Chevron holds working interests ranging from 20 percent to 52 percent in four deepwater blocks that span a total of 178 million acres. Exploration is concentrated in the Campos and Santos basins. In the nonoperated Campos Basin Block BC-20, two areas — 38 percent-owned RJS610 and 30 percent-owned RJS609 — have been retained for development following the end of the exploration phase of this block. In the RJS610 area, a three-well appraisal program on the BC-20-610 Field was completed in December 2005, and results confirmed hydrocarbons from a new Eocene reservoir. FEED for this new field is expected to commence in early 2007. In the RJS609 area, one discovery well was drilled in 2005. Two appraisal wells are planned for 2006. Also in the Campos Basin, the company holds a 30 percent
Argentina: ChevronTexaco operates in Argentina through its subsidiary, Chevron San Jorge S.R.L. The company and its partners hold more than 3.4 million exploration and production acresnonoperated interest in the NeuquénBM-C-4 Block in which one exploration well is planned during 2006. In the 20 percent-owned and Austral basins in 19 production concessions (18 operated and one nonoperated) and seven exploration blocks (five operated and two nonoperated). Working interests range from approximately 19 percent to 100 percent in operated license areas. Farm-out agreements are under negotiations in five blocks. Net production in 2004 averaged 56,000 barrels of oil-equivalent per day.nonoperated Santos Basin BS-4 Block, an additional appraisal well is planned for the second quarter 2006.
Brazil: ChevronTexaco holds working interests ranging from 20 percent to 68 percent in five deepwater blocks totaling 1.5 million acres at year-end 2004. Exploration is concentrated in the Campos and Santos basins. In 2004, the National Petroleum Agency approved the company’s plans to evaluate the discoveries in Block BS-4 and Block BC-20, with completion expected by year-end 2006.      In the Frade Field where(Block BC-4), located in the Campos Basin, the company is the operator and has a 43 percent interest, the contract for front-end engineering design (FEED)interest. FEED for a floating, production, storage and offloading vessel and subsea production systems was awardedcompleted in August2005. Project sanction is expected in 2006, with first oil expected in 2008. Proved undeveloped reserves were recorded for the first time in 2005. The Frade concession expires in 2025.
Colombia: The company operates three natural gas fields in Colombia — the offshore Chuchupa and the onshore Ballena and Riohacha. The fields are part of the Guajira Association contract, a joint venture production-sharing agreement, which was extended in 2003. At that time, additional proved reserves were recognized. The company continues to operate the fields and receives 43 percent of the production for the remaining life of each field as well as a variable production volume from a fixed-fee Build-Operate-Maintain-Transfer (BOMT) agreement based on prior Chuchupa capital contributions. The BOMT agreement expires in 2016. Net production averaged 185 million cubic feet of natural gas per day in 2005. New production capacity is scheduled for commissioning in 2006 and will help meet the demand from the growing Colombian natural gas market.
Trinidad and Tobago: The company has a 50 percent nonoperated interest in four blocks in offshore Trinidad, which include the producing Dolphin natural gas field and two discoveries, Dolphin Deep and Starfish. Net natural gas production from the Dolphin Field in 2005 averaged 115 million cubic feet per day. Natural gas supply to the Atlantic LNG Train 3 from the Dolphin Field began in November 2005. Initial recognition of proved undeveloped reserves associated with the natural gas sales agreement for Train 3 was made in 2003. Proved reserves associated with the Train 4 gas sales agreement were recognized in 2004. TimingInitial production of initial production and booking ofthe Train 4—related reserves is dependent upon FEEDscheduled for the first half of 2006. Reserves associated with Trains 3 and 4 were transferred to the proved developed category in 2005. The contract period for Train 3 ends in 2023 and for Train 4 in 2026. Chevron also holds a 50 percent, operated interest in Block 6d. In early 2005, the company announced successful exploration drilling results which are expectedat the offshore Manatee 1 exploration well in late 2005. NoBlock 6d. The company is assessing alternative development strategies. A unitization agreement is being negotiated between Trinidad and Tobago and Venezuela to develop and produce the Loran and Manatee fields as one project.

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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. Daily net production in 2005 averaged 111,000 barrels of crude oil. The company has not recorded proved reserves under this agreement. The company also has production at the 63 percent-owned LL-652 Field located in Lake Maracaibo. Net production in 2005 averaged 10,000 barrels of oil-equivalent per day. The company operates at LL-652 under a risked service agreement.
      In 2005, the Venezuelan government stipulated that the existing Boscan and LL-652 operating service agreements be converted to an Empresa Mixta (EM), or a Joint Stock contractual structure, with Petróleos de Venezuela, S.A. (PDVSA) as majority shareholder. In December 2005, Chevron signed a transition agreement with PDVSA in order to negotiate the ownership and format of the final EM structure during 2006. Possible financial implications of the EM structure are uncertain but are not expected to have a material effect on the company’s consolidated financial position or liquidity.
      The company has ongoing exploration activity in two blocks offshore Plataforma Deltana. In Block 2, which includes Loran Field, evaluation and project development work continue after an exploration and appraisal program was completed in 2005. Proved reserves have not been recognized for this project. The company is operator and holds a 60 percent interest. In the 100 percent-owned and operated Plataforma Deltana Block 3, Chevron drilled the successful Macuira natural gas discovery well in 2005. This discovery is in close proximity to the Loran natural gas field and provides significant resources that will be included in the detailed evaluation of a project for the possible construction of Venezuela’s first LNG train. Seismic work in Block 3 is planned for 2006. Chevron was awarded the exploration license in 2005 for the 100 percent-owned Cardon III exploration block, located offshore western Venezuela. The block has natural gas potential to the north of the Maracaibo producing region.
      Refer also to page 24 for a discussion of the Hamaca heavy oil production and upgrading project in Venezuela.
     Canada: During 2004,Following the acquisition of Unocal, the company divested producing assets in western Canada and sold its wholly owned mid-stream natural gas processing business. The effectcompleted the sale of these sales on 2004 net oil-equivalent production was about 16,000 barrels per day.Northrock Resources Limited for approximately $1.7 billion. The company continues to maintain strategically significant assets in Canada, including a 27 percent nonoperated interest in the Hibernia Field; a 20 percent nonoperated interest in the Athabasca Oil Sands Project, which is discussed separately on page 26;29; a 28 percent operated interest in the Hebron project, where feasibility studies preceding the major development project are continuing; and exploration opportunities in the Mackenzie Delta and Orphan Basin. Excluding Athabasca and Northrock, daily net daily production in 20042005 from the company’s Canadian operations was 62,00052,000 barrels of crude oil and natural gas liquids and 516 million cubic feet of natural gas.
Colombia: Until the end of 2004, ChevronTexaco operated three natural gas fields under two related contracts — the Guajira Association contract and the Build-Operate-Maintain-Transfer (BOMT) contract. The Guajira Association Contract, a 50-50 joint venture production-sharing agreement, expired in December 2004. In 2005, the company continues to operate the fields and receives 43 percent of the production for the remaining life of the fields, as well as continue to operate the BOMT contract until it expires in 2016. Net natural gas production averaged 210 million cubic feet per day in 2004.
Denmark: ChevronTexaco holds a 15 percent interest in the Danish Underground Consortium (DUC), producing crude oil and natural gas from 15 fields in the Danish North Sea and involving 12 percent to 27 percent interest in five exploration areas. The daily net production from the DUC was 46,000 barrels of crude oil and 130 million cubic feet of natural gas.

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Faroe Islands: In January 2005, the company was awarded five offshore exploration blocks in the Faroe Islands second offshore licensing round. The blocks cover approximately 170,000 acres and are near the recent Rosebank/ Lochnagar discovery in the United Kingdom. The company has a 40 percent interest and will be operator.
Mexico: In September 2004, ChevronTexaco was awarded authorization from the Mexican Environment and Natural Resources Secretariat for its Environmental Impact Assessment and Risk Assessment for the construction of a proposed LNG receiving and regasification terminal offshore Baja California and, in December, was awarded a natural gas storage permit from the Mexican Regulatory Energy Commission. Also in 2004, the company received notice from the Mexican Communication and Transport Secretariat, through its Port Authority, that it was the winner of the public licensing round for the offshore port terminal.
Norway: At the Draugen Field, where ChevronTexaco holds about an 8 percent interest, the company’s share of production during 2004 was 11,000 barrels of crude oil per day.
Russia: In September 2004, the company and OAO Gazprom signed a six-month memorandum of understanding to jointly undertake feasibility studies for the possible implementation of projects in Russia and the United States. This represents a possible opportunity to participate in the development of the vast natural gas and crude oil resource base in Russia and to develop a close partnership with Russia’s largest natural gas producer.
Trinidad and Tobago: The company has a 50 percent nonoperated interest in four blocks offshore Trinidad. Net natural gas production in 2004 averaged 135 million cubic feet per day. In 2005, the company announced the successful exploration drilling results at the offshore Manatee 1 exploration well in Block 6d. ChevronTexaco operates and holds a 50 percent interest in the well.
   
 United Kingdom:Denmark: InChevron holds a 15 percent non-operating interest in the United Kingdom,Danish Underground Consortium (DUC), which produces crude oil and natural gas from 15 fields in the company’s total dailyDanish North Sea and has 12 percent to 27 percent interests in five exploration areas. Daily net production in 20042005 from several fieldsthe DUC was 106,00047,000 barrels of crude oil and 340146 million cubic feet of natural gas. Daily net production at

Faroe Islands: In January 2005, the operatedcompany was awarded five offshore exploration blocks in the second offshore licensing round. The blocks cover approximately 170,000 acres and 85 percent-owned Captain Fieldare near the Rosebank/ Lochnagar discovery in the United Kingdom. An extensive 2-D regional seismic program was 56,000 barrelsacquired in 2005 and will be interpreted in 2006. The company has a 40 percent interest in the blocks and is the operator.

Netherlands:Chevron gained interests ranging from 34 percent to 80 percent in nine blocks in the Netherlands sector of crude oil.the North Sea as part of the Unocal acquisition. The company’s share of net daily production in 2004 atfrom four producing blocks during the co-operated and 32 percent-owned Britannia Fieldfive months post-acquisition was about 9,0004,000 barrels of crude oil and 19510 million cubic feet of natural gas. Development drilling at Britannia is expected to continue for several more years. At the Alba Field in the North Sea, where ChevronTexaco holds a 21 percent interest and operatorship, daily net production averaged 14,000 barrels of crude oil and 3 million cubic feet of natural gas. The operated and 50 percent-owned Erskine Field had net daily crude oil production of 8,000 barrels and net natural gas production of 41 million cubic feet.

A crude oil and natural gas discovery was made in the fourth quarter 2004 at the offshore 40 percent-owned and operated Rosebank/ Lochnagar well (213/27-1Z) in the Faroe-Shetland Channel. Further appraisal drilling is planned for 2005.
     ChevronTexacoNorway: At the Draugen Field, where Chevron holds an 8 percent nonoperated interest, the company’s share of production during 2005 was 8,000 barrels of crude oil per day. In September 2005, Chevron participated in the drilling of the Mojave exploration well (also known as Stetind) in PL 283, in which the company holds a 25 percent

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nonoperated interest. The results of this natural gas well were being evaluated in early 2006. In PL 324, in which the company has a 30 percent nonoperated interest, drilling is planned for late 2006. In the 40 percent-owned and operated PL 325, a seismic program will be conducted in mid-2006.
United Kingdom: Offshore United Kingdom, the company’s daily net production in 2005 from several fields was 83,000 barrels of crude oil and 300 million cubic feet of natural gas. Daily net production at the 85 percent-owned and operated Captain Field was 42,000 barrels of crude oil. The company’s share of daily net production in 2005 at the co-operated and 32 percent-owned Britannia Field was 8,000 barrels of crude oil and 176 million cubic feet of natural gas. At the Alba Field in the North Sea, in which Chevron holds a 21 percent interest and operatorship, daily net production averaged 12,000 barrels of crude oil.
      In the fourth quarter 2005, the company was awarded equity in eight exploration blocks under the 23rd United Kingdom Offshore Licensing Round. Four blocks are located adjacent to the Rosebank/ Lochnagar offshore discovery. Chevron will be the operator with a 40 percent interest.
      Chevron also holds a 19 percent interest in Clair, a nonoperated development. Platform and pipeline installation has been successfully completed. One well has been pre-drilled, and over 20 production and water injection wells are to be drilled and completed between late 2004 and early 2008. Initial production began in February 2005 and is expected to reachattain an average daily net daily production of 12,000 barrels of crude oil and 3 million cubic feet of natural gas byin late 2006. Initial recognition of proved reserves was in 2001. Some reserves were reclassified from proved undeveloped to proved developed in late 2004. Further reclassifications willare expected to occur through 2008 related to planned development drilling. Clair has an expected field life of overmore than 20 years.
      Three producing assets, Galley, OrwellJoint development activities continued at the Britannia satellite fields, Callanish and Statfjord fields,Brodgar, where Chevron holds 17 percent and 25 percent interests, respectively. Four development wells were soldcompleted in the first half 2004. The impact2005. First production is expected in early 2007, building to planned daily net production of these sales on 2004 U.K. net daily production was 12,00010,000 barrels of crude oil and 1950 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. Totalgas several months afterstart-up. Proved undeveloped reserves were initially recognized in 2000.In 2006, proved undeveloped reserves are expected to be reclassified to proved developed ahead of planned commencement of production in 2004 averaged

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113,000 barrelsearly 2007. This development has an expected production life of crudeapproximately 15 years.
      Design and construction work progressed on the Captain Area C project to develop the eastern portion of the Captain Field, with first oil per day. The company also has production at the 63 percent-owned LL-652 Field located in Lake Maracaibo. Net production in 2004 averaged 10,000 barrels of oil-equivalent per day. The company operates at LL-652 under a risked service agreement.planned for mid-2006.
      The company also has exploration activityAlder discovery, west of the Britannia Field, is being evaluated as a tie-back to existing infrastructure. Productionstart-up is anticipated in two blocks offshore Plataforma Deltana.2009. Initial reserves are planned to be booked in 2008.
Mexico: In Block 2, which includes Loran Field, two exploratory wells were drilled successfully in 2004. Proved reserves have not been recognized for this project. The company is operator and holds a 60 percent interest in Block 2. Also in August 2004,early 2005, the company was awarded a license for Block 3, for whichexecuted the concession title that would allow construction of the proposed Baja LNG terminal based in offshore Mexican territorial waters. If approved by the company willand various government agencies, the terminal would be operator and holdsconstructed using a 100 percent interest. An exploration program for Block 3 is planned for 2005.gravity-based structure design with an initial processing capacity of approximately 700 million cubic feet per day.
f)     Affiliate Operations
     Kazakhstan: The company holds a 50 percent interest in Tengizchevroil (TCO), which is developing the Tengiz and Korolev crude oil fields located in western Kazakhstan under a40-year concession that expires in 2033. Net oil-equivalent production in 2005 averaged 178,000136,000 barrels per day in 2004.of crude oil and natural gas liquids and 216 million cubic feet of natural gas.
      TCO is currently undertaking a significant expansion composed of two integrated projects referred to as the Second Generation Plant (SGP) and Sour Gas Injection (SGI)/Second Generation Project (SGP). At a total cost in excess of $4approximately $5.5 billion, the expansion isthese projects are designed to increase TCO’s crude oil production capacity by the third quarter 2007 from 298,000the current 300,000 barrels per day to between 430,000460,000 and 500,000 barrels per day by late 2006, depending550,000 barrels. The actual production level within the estimated range is dependent partially on the final effects of the SGI.SGI, which are discussed below.
      SGP involves the construction of a large processing train for treating crude oil and the associated sour (i.e., high in sulfur content) gas. The SGP design is based on the same conventional technology employed in the existing processing trains. In addition to new processing capacity, SGP involves drilling and/or completing 55 production wells in the Tengiz and Korolev reservoirs to generate the volumes required for the new processing train. Proved undeveloped reserves associated with SGP were recognized in 2001. Some of these reserves were reclassified to proved developed in 2004

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2005, based upon completion of certainspecified project milestones. Over the next decade, ongoing field development is expected to result in the maturationreclassification of the currentadditional proved undeveloped reserves to proved developed.
      SGI involves taking a portion of the rich, sour gas separated from the crude oil production at the SGP processing train and re-injecting it into the Tengiz and Korolev reservoirs. ChevronTexacoreservoir. Chevron expects that SGI will have two key effects. First, SGI will reduce the sour gas processing capacity otherwise required at SGP, thereby increasing liquid production capacity and lowering the quantities of sulfur and gas that would otherwise be generated. Second, over time it is expected that SGI will increase production efficiency and recoverable volumes due to the maintenance of higher reservoir pressure from the gas re-injection. Between 20062007 and 2008, the company anticipates recognizing additional proved reserves associated with the SGI expansion. The primary SGI risks include uncertainties about compressor performance associated with injecting high-pressure sour gas and subsurface responses to injection.
      Essentially all of TCO’s production is exported through the CPCCaspian Pipeline Consortium (CPC) pipeline that runs from Tengiz in Kazakhstan to tanker loading facilities at Novorossiysk on the Russian coast of the Black Sea. CPC is working on obtaining shareholder approval for an expansion to fully accommodate increased TCO volumes by 2009. During 2005, TCO sanctioned the Crude Export project and awarded commercial contracts, which will provide additional export routes utilizing rail transportation to the Odessa Ukraine marine terminal and to marine terminals in Aktau, Kazakhstan. In conjunction with existing CPC capacity, the Crude Export project is expected to be expanded in stages through the end of 2008, is anticipatedprovide TCO with sufficient capacity to fully accommodateexport all TCO expansionproduction, including volumes produced by the end of 2007. TCO is currently pursuing alternate transportation routes to accommodate expansion volumesSGI/ SGP, prior to expansion of the end of 2007 as necessary.CPC pipeline.
     Venezuela: ChevronTexacoChevron has a 30 percent interest in the Hamaca heavy oil production and upgrading project located in Venezuela’s Orinoco Belt. The crude oil upgrading began in October 2004. The facility is expected to reach design capacity inIn the first quarter 2005, to processthe facility reached total design capacity of processing and upgrading 190,000 barrels per day of heavy crude oil (8.5° API) and upgrade into 180,000 barrels of lighter, higher-value crude oil (26° API). In 2004,2005, net production averaged 24,00041,000 barrels of crude oiloil-equivalent per day.
Petroleum — Sale of Natural Gas and Natural Gas Liquids
      The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. Outside the United States, the majority of the company’s natural gas sales occur in Thailand, the United Kingdom, Australia, Canada,and Latin America, and in the company’s affiliate operations in Kazakhstan. International natural gas liquids sales take place in the company’s Canadian upstream operations, with lower sales levels in Africa, Australia and Europe. Refer to “Selected Operating Data”Data,” on page FS-10FS-12 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.

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Petroleum — Refining Operations
      Distillation operatingAt the end of 2005, the company’s refining system consisted of 19 fuel refineries and an asphalt plant. The company operated nine of these facilities, and 11 were operated by affiliated companies. For these 20 facilities, crude oil distillation capacity utilization in 2004, adjusted for sales and closures, averaged 9186 percent in the United States (including asphalt plants) and2005, compared with 89 percent worldwide (including affiliates),in 2004. In general, this decrease resulted from planned and unplanned downtime as well as the impact of two hurricanes in the third quarter 2005. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 90 percent in 2005, compared with 91 percent in the United States and 88 percent worldwide in 2003. ChevronTexaco’s capacity utilization at its U.S. fuels refineries (i.e., excluding asphalt plants) averaged 96 percent in 2004, compared with 95 percent in 2003. Capacity utilization at the company’s wholly owned U.S.and cracking and coking facilities, whichcapacity utilization averaged 76 percent and 88 percent in 2005 and 2004, respectively. Cracking and coking units, including fluid catalytic cracking units, are the primary facilities used in fuel refineries to convert heavier products to gasoline and other light products.
      In 2005, the company began an expansion of the Pascagoula, Mississippi, refinery’s fluid catalytic cracking unit to increase its production of gasoline and other light products. Additionally, GS Caltex, the company’s 50 percent-owned affiliate, approved an upgrade project at the650,000-barrel-per-day Yeosu refining complex in South Korea. At a total estimated cost of $1.5 billion, this project is designed to increase the yield of high-value refined products averaged 89 percent and 85 percentreduce feedstock costs through the processing of heavy crude oil.Start-up of these two projects is expected in 20042006 and 2003,2007, respectively.

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      The company’s U.S. West Coast and Gulf Coast refineries produce low-sulfur fuels that meet 2006 federal government specifications. Investments required to produce low-sulfur fuels in Europe, Canada and South Africa have been completed, and clean fuels projects in Australia are scheduled for completion in 2006.
      The company processedprocesses imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 83 percent and 81 percent and 75 percent of ChevronTexaco’sChevron’s U.S. refinery inputs in 2005 and 2004, and 2003, respectively.
      In July 2004, the company acquired an additional interest in the Singapore Refining Company Pte. Ltd. (SRC), increasing ownership from 33 percent to 50 percent. The additional interest in SRC is expected to strengthen the company’s existing strategic position in the Asia-Pacific area, one of the company’s core markets.
      The company’s U.S. West Coast and Gulf Coast refineries produce low sulfur fuels that meet 2006 federal government specifications. Investments required to produce low sulfur fuels in Europe and Canada were completed by the end of 2004 while clean fuel projects in South Africa and Australia are scheduled to be completed in 2005.
The daily refinery inputs over the last three yearsfor 2003 through 2005 for the company and affiliate refineries are shown in the following table.as follows:
Petroleum Refineries: Locations, Capacities and Inputs
(Inputs and Capacities in Thousands of Barrels per Day)
                 
 December 31,  
                   2005 Refinery Inputs
 December 31, 2004 Refinery Inputs    
     Number   2005  
   Operable          
LocationsLocations Number Capacity 2004 2003 2002Locations        
                   
   Operable   2004 2003
   Capacity      
          
Pascagoula Mississippi  1  325  312  301  329  Mississippi  1  325  263  312  301 
Richmond California  1  225  233  233  235 
El Segundo California  1  260  234  242  251  California  1  260  230  234  242 
Richmond California  1  225  233  235  187 
El Paso1
 Texas  –  –  –  36  61 
Kapolei Hawaii  1  54  51  52  53  Hawaii  1  54  50  51  52 
Salt Lake City Utah  1  45  42  40  43  Utah  1  45  41  42  40 
El Paso1
 Texas  —  —  —  —  36 
Other2
  2  96  42  45  55   1  80  28  42  45 
                      
Total Consolidated Companies — United StatesTotal Consolidated Companies — United States  7  1,005  914  951  979 Total Consolidated Companies — United States  6  989  845  914  951 
                       
Pembroke United Kingdom  1  210  209  175  204  United Kingdom  1  210  186  209  175 
Cape Town South Africa  1  112  62  72  74  South Africa  1  110  61  62  72 
Burnaby, B.C. Canada  1  52  49  50  51  Canada  1  55  45  49  50 
Batangas3
 Philippines  –  –  –  49  59  Philippines  —  —  —  —  49 
Colón4
 Panama  –  –  –  –  27 
Escuintla4
 Guatemala  –  –  –  –  11 
                      
Total Consolidated Companies — InternationalTotal Consolidated Companies — International  3  374  320  346  426 Total Consolidated Companies — International  3  375  292  320  346 
Equity Affiliates5
 Various Locations  11  833  724  694  674 
Equity in Affiliates4
 Various Locations  11  831  746  724  694 
                      
Total Including Affiliates — InternationalTotal Including Affiliates — International  14  1,207  1,044  1,040  1,100 Total Including Affiliates — International  14  1,206  1,038  1,044  1,040 
                       
Total Including Affiliates — WorldwideTotal Including Affiliates — Worldwide  21  2,212  1,958  1,991  2,079 Total Including Affiliates — Worldwide  20  2,195  1,883  1,958  1,991 
                       
 1ChevronTexacoChevron sold its interest in the El Paso Refinery in August 2003.
 2RefineriesAsphalt plants in Perth Amboy, New Jersey, and Portland, Oregon, are primarily asphalt plants.Oregon. The Portland plant was sold in February 2005.
 3ChevronTexacoChevron ceased refining operations at the Batangas Refinery in November 2003 in advance of the refinery’s conversion into a finished-product terminal.
 4ChevronTexaco 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.
5ChevronTexacoChevron increased its ownership interest in the Singapore Refining Company Pte. Ltd. from 33 percent to 50 percent in July 2004. This increased the company’s share of operable capacity at December 31, 2004, by about 48,000 barrels per day.

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

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      The following table shows the company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ending December 31, 2004.2005.
Refined Products Sales Volumes1
(Thousands of Barrels per Day)
                    
 2004 2003 2002  2005 2004 2003
             
United StatesUnited States          United States          
Gasolines  701  669  680 Gasolines  709  701  669 
Jet Fuel  302  314  352 Jet Fuel  291  302  314 
Gas Oils and Kerosene  218  196  259 Gas Oils and Kerosene  231  218  196 
Residual Fuel Oil  148  123  177 Residual Fuel Oil  122  148  123 
Other Petroleum Products2
  137  134  132 
Other Petroleum Products2
  120  137  134 
               
Total United States
  1,506  1,436  1,600 
Total United States
  1,473  1,506  1,436 
               
International3
International3
          
International3
          
Gasolines  717  643  620 Gasolines  669  717  643 
Jet Fuel  250  228  207 Jet Fuel  259  250  228 
Gas Oils and Kerosene  805  780  783 Gas Oils and Kerosene  784  805  780 
Residual Fuel Oil  463  487  416 Residual Fuel Oil  410  463  487 
Other Petroleum Products2
  167  164  149 
Other Petroleum Products2
  173  167  164 
               
Total International
  2,402  2,302  2,175 
Total International
  2,295  2,402  2,302 
               
Total Worldwide3
Total Worldwide3
  3,908  3,738  3,775 
Total Worldwide3
  3,768  3,908  3,738 
               
                        
1 Includes buy/sell arrangements:
  180  194  197   217  180  194 
2 Principally naphtha, lubricants, asphalt and coke.2 Principally naphtha, lubricants, asphalt and coke.          
3 Includes equity affiliates.
3 Includes share of equity affiliates’ sales:  540  536  525 
      In the United States, the company markets under the Chevron and Texaco brands. The company supplies directly or through retailers and marketers almost 9,0009,300 branded motor vehicle retail outlets, concentrated in the southern, eastern,southeastern, southwestern and western states. Approximately 700600 of the outlets are company-owned or -leased stations. By the end of the year,2005, the company was supplying more than 1,0001,600 Texaco retail sites, primarily in the Southeast. The Company plans to supply additional sites in the Southeast and West during 2005.
      Outside ofWest. Further expansion is planned when all rights to the Texaco brand in the United States ChevronTexacorevert to Chevron in July 2006.
      Outside the United States, Chevron supplies directly or through retailers and marketers approximately 16,70017,200 branded service stations, including affiliates, in nearly 90 countries. In Canada, primarily in British Columbia, Canada, the company markets under the Chevron brand name.brand. In Europe, the company has marketing operations under the Texaco brand primarily in the United Kingdom, Ireland, the Netherlands, Belgium Luxembourg and the Canary Islands.Luxembourg. In West Africa, the company operates or leases to retailers in Cameroon, Côte d’Ivoire, Nigeria, Republic of the Congo, Togo and Benin. In these regions, the company mainly uses the Texaco brand name.brand. The company also operates across the Caribbean, Central America and South America, with a significant presence in Brazil, using the Texaco brand name.brand. In the Asia-Pacific region, Southern, Central and East Africa, Egypt, and Pakistan, ChevronTexacothe company uses the Caltex brand name.brand.
      The company also operates through affiliates under various brand names. In Denmark and Norway, the company operates through its 50 percent-owned affiliate, HydroTexaco, using the Y-X and Uno-X brands. In the United Arab Emirates, the company operates through its 40-percent-owned Emirates Petroleum Products Co. joint venture, using the EPPCO brand. In South Korea, the company operates through its 50-percent-owned50 percent-owned affiliate, LGGS Caltex, using the LGGS Caltex brand. This brand name will become GS Caltex effective March 31, 2005. The company’s 50-percent-owned50 percent-owned affiliate in Australia operates primarily using the Caltex, brand.Caltex Woolworths and Ampol brands. In the United Arab Emirates, the company sold its 40 percent interest in the Emirates Petroleum Products Co. joint venture in 2005.

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      Throughout 2004, theThe company continued the marketing and sale of service station sites, focusing on selected areas outside the United States in 2005. More than 700 service stations were sold, primarily in the United Kingdom and Latin America. Since the beginning of 2003, the company has sold its interests in more than 2,300 service station sites. Worldwide, dispositions totaling nearly 1,600The vast majority of these sites occurred as part of a decapitalization program in 2003 and 2004. In most cases, current sales volumes will continue to market company-branded gasoline through branded salesnew supply agreements.

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      In addition to the above activities, theThe company also manages other marketing businesses globally. In global aviation fuel marketing, the companyChevron markets 500,000 barrels per day of aviation fuel in 80approximately 70 countries, representing a worldwide market share of about 12 percent. The companypercent, and is the leading marketer of jet fuels in the United States. ChevronTexacoThe company also markets an extensive line of lubricant products in about 170175 countries.
Petroleum — Transportation
     Pipelines: ChevronTexacoChevron 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, 20042005
      
  Net Mileage1
   
United States:    
 
Crude Oil2
  2,1892,882 
 Natural Gas  2,1542,275 
 
Petroleum Products3
  5,3307,181 
    
 
Total United States
  9,67312,338 
International:    
 
Crude Oil2
  431451 
 Natural Gas  767426 
 
Petroleum Products3
  567433 
    
 
Total International
  1,7651,310 
    
Worldwide
  11,43813,648 
    
1Partially owned pipelines are included atin the company’s equity percentage.
2Includes gathering lines related to the transportation function. Excludes gathering lines related to the U.S. and international production activities.
3Includes refined products, chemicals and natural gas liquids.
     In the United States, the company increased its equity ownership in Bridgeline Holdings, L.P. (BLH) to 100 percent in 2005. Located in southern Louisiana along the Mississippi River corridor, BLH manages and operates an integrated intrastate natural gas pipeline and storage system, consisting of more than 1,000 miles of pipeline and 12 billion cubic feet of natural gas storage capacity, and manages marketing, supply and transportation functions. Through the Unocal acquisition, the company obtained operated and nonoperated interests in natural gas storage assets in Canada, Texas and Alaska, with total storage capacity of 74 billion cubic feet. In addition, the company acquired ownership of the Beaumont Terminal, a nonregulated terminal in Texas that handles a range of commodities. The acquisition also provided the company with ownership interests in about 2,000 net pipeline miles, including a 23 percent interest in the Colonial Pipeline Company and a 64 percent interest in the Southcap Pipeline Company.
      Chevron also has a 15 percent ownership interest in the Caspian Pipeline Consortium (CPC). CPC operates a crude oil export pipeline from the Tengiz Field in Kazakhstan to the Russian Black Sea port of Novorossiysk. At the end of 2004,2005, CPC had 1011 transportation agreements in place and was transporting 550,000an average of 520,000 barrels of crude oil per day from the Caspian region. Russian crude oil entered CPCthe pipeline in late 2004 and is forecasted to rise to about 120,000averaged 130,000 barrels per day during 2005, bringing the pipeline capacitytotal volume transported to 670,000650,000 barrels of crude oil per day.
      TheFor information on projects under way related to the Chad-Cameroon pipeline, system is expandablethe West African Gas Pipeline, the Baku-Tbilisi-Ceyhan pipeline and the expansion of the CPC pipeline, refer to 1.4 million barrels per day with additional pump stationspages 14, 16, 18 and tanks. CPC is in the initial planning stages of expanding the system. Expansion is expected to be completed in phases, with a total cost estimated at $2 billion. Full build-out to 1.4 million barrels per day is currently scheduled to be complete by the end of 2008 with additional planned capacity to begin operating in 2006 and 2007. ChevronTexaco has a 15 percent ownership interest in CPC.24, respectively.

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     Tankers: ChevronTexaco’s controlled seagoing fleet at December 31, 2004, is summarized in the following table. All controlled tankers were utilized in 2004. In addition, atAt any given time during 2005, the company hashad approximately 70 vessels under a voyage basis or as time charterscharter of less than one year. Additionally, all tankers in Chevron’s controlled seagoing fleet were utilized during 2005. The following table summarizes cargo transported on the company’s controlled fleet.
Controlled Tankers at December 31, 20042005
                                  
 U.S. Flag Foreign Flag Number  U.S. Flag Foreign Flag
         
   Cargo Capacity   Cargo Capacity    Cargo Capacity   Cargo Capacity
 Number (Millions of Barrels) Number (Millions of Barrels)  Number (Millions of Barrels) Number (Millions of Barrels)
                 
OwnedOwned  3  0.8  –  – Owned  3  0.8  —  — 
Bareboat CharteredBareboat Chartered  –  –  16  22.3 Bareboat Chartered  —  —  18  26.7 
Time Chartered*Time Chartered*  –  –  19  10.1 Time Chartered*  —  —  18  9.3 
                   
Total
  3  0.8  35  32.4 
Total
  3  0.8  36  36.0 
* One year or greater.
     Federal law requires that cargo transported between U.S. ports be carried in ships built and registered in the United States, owned and operated by U.S. entities and manned by U.S. crews. At year-end 2004,2005, the company’s U.S. flag fleet was engaged primarily in transporting refined products between the Gulf Coast and the East Coast, and from California refineries to terminals on the West Coast and in Alaska and Hawaii.
      The international flag vessels were engaged primarily in transporting crude oil from the Middle East, Indonesia, Mexico and West Africa to ports in the United States, Europe and Asia. Refined products were also were transported by tanker worldwide.
      In addition to the vessels described above, the company owns a one-sixth interest in each of seven liquefied natural gas (LNG) tankers transporting cargoes for the North West Shelf (NWS) project in Australia. In early 2004, the company assumed full operatorship of one of the tankers, theNorthwest Swan, on behalf of the project’s participants. Additionally, the NWS project has two LNG tankers under long-term time charter. In 2005, the company placed orders for two additional LNG tankers to support planned growth in the company’s LNG business. These carriers are planned to be delivered in 2009.
      The Federal Oil Pollution Act of 1990 requires the scheduled phase-out, by year-end 2010, of all single-hull tankers trading to U.S. ports or transferring cargo in waters within the U.S. Exclusive Economic Zone. This has raised the demand for double-hull tankers. By the end of 2004, ChevronTexaco2005, Chevron had a total of 1820 company-operated double-hull tankers in operation. The company is a member of many oil-spill-response cooperatives in areas around the world in which it operates.
Chemicals
      Chevron Phillips Chemical Company LLC (CPChem) is a 50-50 joint ventureequally owned with ConocoPhillips Corporation. CPChem owns or has joint venture interests in 3231 manufacturing facilities and six research and technical centers in the United States, Puerto Rico, Belgium, China, Mexico, Saudi Arabia, Singapore, South Korea and Qatar.
      In 2004, along with its Saudi partner, CPChem secured approvals to proceed with2005, construction of anprogressed on CPChem’s integrated, world-scale styrene facility along with the expansion of an existing, adjacently located aromatics plant in Al Jubail, Saudi Arabia. Jointly owned with the Saudi Industrial Investment Group (SIIG), the project’s operationalstart-up is anticipated in late 2007. CPChem and SIIG currently operate an aromatics complex in Al Jubail.
      In the fourth quarter 2005, CPChem approved the continued development of plans for a third petrochemical project in Saudi Arabia. Preliminary studies are focused on the construction of a world-scale olefins unit, as well as downstream units, to produce polyethylene, polypropylene, 1-hexene and polystyrene. This $1.2 billionproject would capitalize on CPChem’s proven technologies and be located in Al Jubail, next to CPChem and SIIG’s existing aromatics complex and the styrene facility currently under construction. Final approval of the project is scheduled for completionexpected in the first half of 2008.2007.
      Also during 2004, CPChem continued the development of2005, approvals were obtained and financial closing completed for the Q-Chem II project, which will include a350,000-metric-ton-per-year polyethylene plant and a345,000-metric-ton-per-year normal alpha olefins plant — each utilizing CPChem proprietary technology — located adjacent to the existing Q-Chem I complex in

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Mesaieed, Qatar. The Q-Chem II project also includes a separate joint venture to develop a1,300,000-metric-ton-per-year ethylene cracker at Qatar’s Ras Laffan ethylene projectsIndustrial City, in Qatar. Final approvals bywhich Q-Chem II owns 54 percent of the projectcapacity rights. CPChem and its partners for this world-scale olefinsexpect to start up the cracker and polyolefins development are expectedderivatives plants in 2005.late 2008. CPChem owns a 49 percent interest of Q-Chem II.
      ChevronTexaco’sChevron’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, Brazil, France, the Netherlands, Singapore and Japan and has equity interests in facilities in India and Mexico. In January 2005,The previously announced decision to close the company announced it is closing its manufacturing plant in Brazil. The closure is expectedBrazil was reversed in 2005 due to be completed by the end of 2005.increased worldwide demand for additives.

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      Oronite provides additives for lubricating oil in most engine applications, such as passenger car, heavy-duty diesel, marine, two-cycle and railroad engines, and additives for fuels to improve engine performance and extend engine life.
Coal and Other Minerals
      The company’s coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), owned and operated two surface mines, McKinley, in New Mexico, and Kemmerer, in Wyoming, and one underground mine, North River, in Alabama, at year-end 2004. In addition, final2005. Final reclamation activities were under waycompleted at the York Canyon and Farco mines,surface mine located in New Mexico, and Texas, respectively. P&M also owns an approximatereclamation activities continued in 2006 at the Farco surface mine in Texas. Chevron sold its 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.
late 2005. Sales of coal from P&M’s wholly owned mines and from its affiliates were 14.614.1 million tons, an increase of 9 percentrelatively unchanged from 2003. The increase was primarily a result of higher production at P&M’s surface mine located near Gallup, New Mexico.2004.
      At year-end 2004,2005, P&M controlled approximately 167235 million tons of developed and undeveloped coal reserves in the United States, including reserves of environmentally desirable low-sulfur coal. The company is contractually committed to deliver approximately 14 million tons of coal per year through the end of 2006 and believes it canwill satisfy these contracts from existing coal reserves.
      The company acquired Molycorp Inc., which mines and markets molybdenum and rare earth minerals, as part of the Unocal acquisition. At year-end 2005, Molycorp owned and operated the Questa molybdenum mine in New Mexico and the Mountain Pass lanthanides mine in California. In addition, Molycorp owns a 35 percent interest in Companhia Brasileira de Metalurgia e Mineracao, a producer of niobium in Brazil, and a 33 percent interest in Sumikin Molycorp, a manufacturer of neodymium compounds, located in Japan. During 2005, Molycorp performed environmental remediation activities at Questa, New Mexico and Mountain Pass, California, and closed certain operations in Colorado and Pennsylvania.
      At year-end 2005, Molycorp controlled approximately 53 million pounds of developed and undeveloped molybdenum reserves at Questa and 241 million pounds of lanthanide reserves at Mountain Pass. Molycorp’s share of niobium reserves totaled 1.9 million tons.
      Also as part of the Unocal acquisition, the company acquired the Chicago Carbon Company that operates a250,000-ton-per-year petroleum coke calciner facility in Illinois.
Synthetic Crude Oil
      In Canada, ChevronTexacoChevron holds a 20 percent nonoperatingnonoperated interest in the Athabasca Oil Sands Project (AOSP). Bitumen is extracted from oil sands and upgraded into synthetic crude oil using hydroprocessing technology. The integrated operation at AOSP commenced in 2003 withramp-up of production continuingsubstantially completed in 2004.2005. Total 20042005 bitumen production averaged 134,000158,000 barrels per day (about 27,00032,000 net barrels). At full capacity inNet proved oil sands reserves at the end of 2005 were 146 million barrels.
      In early 2006, the company was evaluating feasibility of a proposed AOSP expansion. The expansion would be designed to produce approximately 100,000 barrels of bitumen per day (20,000 net barrels) and upgrade it into synthetic crude oil. If the AOSP expansion project proceeds, first production is expected to reach total production of 155,000 barrels per day.in late 2009. No proved oil sands reserves have been recorded in association with this expansion.

29

Global Power Generation
      ChevronTexaco’sChevron’s Global Power Generation (GPG) business has more than 20 years experience in developing and operating commercial power projects. With 13projects and owns 16 power assets located in the United States and Asia,Asia. GPG manages the production of more than 3,3003,500 megawatts of electricity in its facilities. All of theat 13 facilities are ownedit owns through joint ventures. The company operates efficient gas-fired cogeneration facilities somethat use waste heat recovery to produce additional electricity or to support industrial thermal hosts. A number of whichthe facilities produce steam for use in upstream operations to facilitate production of heavy oil.
      In 2005, the company acquired an additional 13 percent in the Tri Energy Company, a 700-megawatt independent power producer located in Ratchaburi Province, Thailand, increasing Chevron’s total ownership to 50 percent.
Gas-to-LiquidsGas-to-Liquids
      The 50-50 Sasol Chevron Global 50-50 Joint Venture was established in October 2000 to develop a worldwide gas-to-liquidsgas-to-liquids (GTL) business. Through this venture, the company is engaged in discussions with Qatar Petroleum (QP) on a number of projects, which include the design, construction and operation of a base oils production facility downstream of the Sasol and QP Oryx GTL plant in Qatar, and evaluation of an expansion of the Oryx GTL foundation plant from 34,000 to 100,000 barrels per day.
In Nigeria, construction for the planned gas-to-liquidsChevron Nigeria Limited and the Nigerian National Petroleum Corporation are developing a 34,000-barrel-per-day GTL facility at Escravos is expected to beginthat will process natural gas supplied from the output of the Phase 3 expansion of the Escravos Gas Plant (EGP). The $1.7 billion engineering, procurement and construction contract was awarded in April 2005. Plant construction began in 2005, pending finalization of fiscal terms. Projectsincluding major equipment fabrication and site preparation. Refer also to build GTL plantspage 16 for a discussion on the EGP Phase 3 expansion.
Chevron Energy Solutions
      Chevron Energy Solutions (CES) is a wholly owned subsidiary that provides public institutions and businesses with projects that are being considereddesigned to increase energy efficiency, reduce energy costs and ensure reliable, high-quality power for Qatarcritical operations. CES has offices in the United States and Australia.has energy-saving projects installed in more than a thousand buildings nationwide.
Research and Technology
      The company’s Energy Technology Company delivers integrated technologies and services to the upstream, downstream and gas-based businesses. These activities include deepwater exploration and production systems, reservoir management and optimization, heavy oil recovery and upgrading, shallow-water production operations, gas-to-liquidsgas-to-liquids processing, improved refining processes, and safe, incident-free plant operations, and technical computing. The Information Technology Company provides a standardized digital infrastructure as well as information management and security for the company’s global operations.
      Additionally, ChevronTexaco’sChevron’s Technology Ventures Company focuses on identification, growth(CTV) identifies, grows and commercialization ofcommercializes emerging technologies that have the potential to transform how energy is produced or consumed. TheCTV’s activities range of business spansfrom early-stage investing of venture capital in emerging technologies to developing joint venture companies in new energy systems, such as hydrogen infrastructure, advanced battery systems,batteries, nano-materials and renewable energy applications.
      ChevronTexaco’sChevron’s research and development expenses were $316 million, $242 million $228 million and $221$228 million for the years 2005, 2004 and 2003, and 2002, respectively.

26

      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

30

and complexity and to govern not only the manner in which the company conducts its operations, but also the products it sells. ChevronTexacoChevron expects more environmental-related regulations in the countries where it has operations. Most of the costs of complying with the many laws and regulations pertaining to its operations are embedded in the normal costs of conducting its business.
      In 2004,2005, the company’s U.S. capitalized environmental expenditures were $145$227 million, representingwhich includes $2 million for Unocal activities for the last five months of 2005 and which represents approximately 56 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 segmentupstream and downstream segments and relate mostly to air-and-water qualityair- and water-quality projects and activities at the company’s refineries, oil and gas producing facilities, and marketing facilities. For 2005,2006, the company estimates U.S. capital expenditures for environmental control facilities will be approximately $240$452 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 ChevronTexacoChevron and on the company’s 20042005 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-15FS-18 to FS-16,FS-19, and on page FS-18FS-21 toFS-22 of this Annual Report on Form 10-K.
WebsiteWeb Site Access to SEC Reports
      The company’s Internet websiteWeb site can be found athttp://www.chevrontexaco.com/www.chevron.com/. Information contained on the company’s Internet websiteWeb site is not part of this Annual Report on Form 10-K report.10-K.
      The company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on the company’s website,Web site, free of charge, soon after such reports are filed with or furnished to the SEC.
Alternatively, you may access these reports at the SEC’s Internet website:Web site:http://www.sec.gov/.
Item 1A.       Risk Factors
      Chevron is a major fully integrated petroleum company with a diversified business portfolio, strong balance sheet, and a history of generating sufficient cash to fund capital and exploratory expenditures and to pay dividends. Nevertheless, some inherent risks could materially impact the company’s financial results of operations or financial condition.
Chevron is exposed to the effects of changing commodity prices.
      Chevron is primarily in a commodities business with a history of price volatility. The single largest variable that affects the company’s results of operations is crude oil prices. Except in the ordinary course of running an integrated petroleum business, Chevron does not seek to hedge its exposure to price changes. A significant, persistent decline in crude oil prices may have a material adverse effect on its results of operations and its capital and exploratory expenditure plans.
The scope of Chevron’s business will decline if the company does not successfully develop resources.
      The company is in an extractive business; therefore, if Chevron is not successful in replacing the crude oil and natural gas it produces with good prospects for future production, the company’s business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining rights to explore, develop and produce hydrocarbons in promising areas, drilling success, ability to bring long lead-time, capital intensive projects to completion on budget and schedule, and efficient and profitable operation of mature properties.
The company’s operations could be disrupted by natural or human factors.
      Chevron operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations and facilities are therefore subject to disruption from either natural or human causes, including hurricanes, earthquakes,

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floods and other forms of severe weather, war, civil unrest and other political events, fires and explosions, any of which could result in suspension of operations, or harm to people or the natural environment.
Chevron’s business subjects the company to liability risks.
      The company produces, transports, refines and markets materials with potential toxicity, and it purchases, handles and disposes of other potentially toxic materials in the course of the company’s business. Chevron operations also produce byproducts, which may be considered pollutants. Any of these activities could result in liability, either as a result of an accidental, unlawful discharge or as a result of new conclusions on the effects of the company’s operations on human health or the environment.
Political instability could harm Chevron’s business.
      The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates. As has occurred in the past, actions could be taken by host governments to increase public ownership of the company’s partially- or wholly owned businesses, and/or to impose additional taxes or royalties.
      In certain locations, host governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries. Internal unrest, acts of violence or strained relations between a host government and the company or other governments may affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results, and are carefully considered by management when evaluating the level of current and future activity in such countries. At December 31, 2005, approximately 23 percent of the company’s proved reserves were located in Kazakhstan. The company also has significant interests in Organization of Petroleum Exporting Countries (OPEC)-member countries including Indonesia, Nigeria and Venezuela. Approximately 22 percent of the company’s net proved reserves, including affiliates, were located in OPEC countries at December 31, 2005.
Item 1B.       Unresolved Staff Comments
      None.
Item 2.Properties
      The location and character of the company’s crude oil, natural gas and coal properties and its refining, marketing, transportation and chemicals facilities are described above under Item 1. BusinessBusiness. 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-57FS-65 to FS-68FS-78 of this Annual Report on Form 10-K. Note 15,14, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-41FS-46 of this Annual Report on Form 10-K.
Item 3.Legal Proceedings
None.      The South Coast Air Quality Management District (AQMD) has issued several notices of violation to the Chevron Products Company, a division of Chevron U.S.A., Inc, alleging more than 160 violations of the AQMD’s Rule 463, which regulates emissions from floating roof tanks, at the company’s El Segundo, California, refinery, as previously reported in the company’s quarterly report on Form 10-Q for the period ended September 30, 2005. It was also noted that in August 2005, the AQMD contacted the company to ask that these violations be consolidated with a newly discovered matter involving alleged violations of the AQMD’s Rule 1173 concerning Leak Detection and Repair of components that emit volatile organic compounds. The company has settled these matters by agreeing to pay a civil penalty of $5 million and $1.5 million in emission fees.
Item 4.Submission of Matters to a Vote of Security Holders
None.

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Executive Officers of the Registrant at March 1, 20052006
       
Name and Age
 Executive Office Held Major Area of Responsibility
     
D. J.D.J. O’Reilly 5859 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.P.J. Robertson 5859 Office of the Chairman since 2005
Vice Chairman of the Board since 2002
Vice President from 1994 to 2001
President of Chevron Overseas Petroleum Inc.
  from 2000 to 2002
Executive Committee Member since 1997		 Office of the Chairman; Strategic Planning; Policy, Government and Public Affairs; Human Resources
 
J. E.J.E. Bethancourt 5354 Executive Vice President since 2003
Executive Committee Member since 2003		 Technology; Chemicals; Coal; Health, Environment and Safety
 
G. L.G.L. Kirkland 5455 Executive Vice President since 2005
President of ChevronTexacoChevron Overseas
  Petroleum Inc. from 2002 to 2004
Vice President from 2000 to 2004
President of Chevron U.S.A. Production
  Company from 2000 to 2002
Executive Committee Member
  from 2000 to 2001 and since 2005		 Worldwide Exploration and Production Activities and Global Gas Activities, including Natural Gas Trading
 
S. Laidlaw 4950 Executive Vice President since 2003
Executive Committee Member since 2003		 Business Development
 
P. A. WoertzM.K. Wirth 5145 Executive Vice President, since 2001effective
Vice President since 1998  March 1, 2006
President of Chevron Products CompanyGlobal Supply and Trading
  from 19982004 to 20012006
Executive Committee Member since 19982006		 Global Refining, Marketing, Lubricants, and Supply and Trading, excluding Natural Gas Trading
 
S. J.S.J. Crowe 5758 Vice President and Chief Financial Officer
  since 2005
Vice President and Comptroller from 20012000
  tothrough 2004
Vice President and Comptroller of
  Chevron Corporation from 1996 to 20012000
Executive Committee Member since 2005		 Finance
 
C. A.C.A. James 5051 Vice President and General Counsel
  since 2002
Executive Committee Member since 2002		 Law
 
J. S.J.S. Watson 4849 President of ChevronTexaco OverseasChevron International
  Petroleum Inc.Exploration & Production since 2005
Vice President and Chief Financial Officer
  from 2000 tothrough 2004
Executive Committee Member
  from 2000 to 2004		 OverseasInternational Exploration and Production
 
R. I. WilcoxR.I. Wilcox* 5960 President, ChevronTexacoChevron North America
  Exploration &
Production Company
  since 2002
Vice President since 2002		 North American Exploration and Production
* Effective March 31, 2006, R.I. Wilcox will retire from the company. Wilcox will be succeeded by G.P. Luquette, managing director of the European strategic business unit of Chevron International Exploration & Production Company.

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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.J.E. Bethancourt - Vice President, Texaco Inc., President of Production Operations, Worldwide Exploration and Production, Texaco Inc. –— 2000
  - Vice President, Human Resources, ChevronTexacoChevron Corporation –— 2001
  - Executive Vice President, ChevronTexacoChevron Corporation –— 2003
 
S. J. Crowe -Comptroller, Chevron Corporation – 1996
-Vice President and Comptroller, Chevron Corporation – 2000
-Vice President and Comptroller, ChevronTexaco Corporation – 2001
C. A.C.A. James - Partner, Jones Day (a major U.S. law firm) –— 1992
  - Assistant Attorney General, Antitrust Division, U.S. Department of Justice –— 2001
  - Vice President and General Counsel –— 2002
 
G. L. Kirkland -General Manager, Asset Management, Chevron Nigeria Limited – 1996
-Chairman and Managing Director, Chevron Nigeria Limited – 1996
-President, Chevron U.S.A. Production Company – 2000
-President, ChevronTexaco Overseas Petroleum Inc. – 2002
S. Laidlaw - President and Chief Operating Officer, Amerada Hess –— 2001
  - Chief Executive Officer, Enterprise Oil plc –— 2002
  - Executive Vice President, ChevronTexacoChevron Corporation –— 2003
 
J. S. Watson -President, Chevron Canada Limited – 1996
-Vice President, Strategic Planning, Chevron Corporation – 1998
-Vice President and Chief Financial Officer, Chevron Corporation – 2000
R. I.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, ChevronTexacoChevron North America Exploration & Production Company –— 2002
M.K. Wirth-General Manager, U.S. Retail Marketing, Chevron Products Company — 1999
-President, Marketing, Caltex Corporation — 2000
-President, Marketing, Asia, Middle East and Africa Marketing Business Unit, Chevron Corporation — 2001
-President, Global Supply and Trading — 2004
-Executive Vice President, Chevron Corporation — 2006

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PART II
Item 5.       Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
      The information on ChevronTexaco’sChevron’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-22FS-26 of this Annual Report on Form 10-K.
CHEVRONTEXACOCHEVRON CORPORATION
ISSUER PURCHASES OF EQUITY SECURITIES
                 
        Maximum
      Total Number of Number of Shares
  Total Number Average Shares Purchased as that May Yet Be
  of Shares Price Paid Part of Publicly Purchased Under
Period Purchased (1)(2) per Share (2) Announced Program the Program
         
Oct. 1 – Oct. 31, 2004  2,995,294   54.36   2,345,100   — 
Nov. 1 – Nov. 30, 2004  5,838,650   53.67   5,545,600   — 
Dec. 1 – Dec. 31, 2004  6,348,653   52.69   6,158,821   — 
             
Total Oct. 1 – Dec 31, 2004
  15,182,597   53.40   14,049,521   (3)
             
                 
        Maximum
      Total Number of Number of Shares
  Total Number Average Shares Purchased as that May Yet Be
  of Shares Price Paid Part of Publicly Purchased Under
Period Purchased(1),(2) per Share Announced Program the Program
         
Oct. 1 – Oct. 31, 2005  3,612,153   61.12   3,515,000   — 
Nov. 1 – Nov. 30, 2005  7,879,941   57.73   7,622,200   — 
Dec. 1 – Dec. 31, 2005  2,013,065   57.77   1,737,000   — 
             
Total Oct. 1 – Dec 31, 2005
  13,505,159   58.64   12,874,200   (2)
             
 
(1)Includes 74,67943,905 common shares repurchased during the three-month period ended December 31, 20042005 from company employees for required personal income tax withholdings on the individual’s exercise of the stock options issued to management and employees under the company’s broad-based employee stock options, long-term incentive plans and former Texaco Inc. stock option plans. Additionally,Also includes 1,058,397587,054 shares delivered or attested to in satisfaction of the exercise price by holders of certain former Texaco Inc. employee stock options exercised during the three-month period ended December 31, 2004.2005.
 
(2)All share and per share value amounts reflect the two-for-one stock split in September 2004.
(3) On March 31, 2004, the company announced a $5 billion common stock repurchase program. Acquisitions of up to $5 billion will be made from time to time at prevailing prices as permitted by securities laws and other requirements, and subject to market conditions and other factors. The program will occur overwas completed on November 23, 2005, at which time 92,096,099 shares had been repurchased for a periodtotal of up to three years and may be discontinued at any time. Through December 31, 2004, $2.1 billion has been expended to repurchase 42,324,089 shares since the common stock repurchase program began.$5 billion.
In December 2005, the company authorized stock repurchases of up to $5 billion that may be made from time to time at prevailing prices as permitted by securities laws and other requirements and subject to market conditions and other factors. The program will occur over a period of up to three years and may be discontinued at any time. As of December 31, 2005, a total of 1,737,000 shares had been acquired under this program for $100 million.
Item 6.       Selected Financial Data
      The selected financial data for years 20002001 through 20042005 are presented on page FS-57FS-64 of this Annual Report on Form 10-K.
Item 7.       Management’s Discussion and Analysis of Financial Condition and Results of Operations
      The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1 of this Annual Report on Form 10-K.
Item 7A.       Quantitative and Qualitative Disclosures About Market Risk
      The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Financial and Derivative Instruments,” beginning on page FS-14FS-17 and in Note 87 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-35.FS-39.

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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
       ChevronTexacoChevron Corporation’s Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the company’s “disclosure controls and procedures” (as defined in Rules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of December 31, 2004,2005, have concluded that as of December 31, 2004,2005, the company’s disclosure controls and procedures were effective and designed to provide reasonable assurance that material information relating to the company and its consolidated subsidiaries required to be included in the company’s periodic filings under the Exchange Act would be made known to them by others within those entities.
      (b)       Management’s Report on Internal Control Over Financial Reporting
       The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule Rules 13a-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on theInternal Control –— Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the company’s management concluded that its internal control over financial reporting was effective as of December 31, 2004.2005.
 
       The company management’s assessment of the effectiveness of its internal control over financial reporting as of December 31, 20042005, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in theirits report whichthat is included herein.on page FS-28 of this Annual Report on Form 10-K.
      (c)       Changes in Internal Control Over Financial Reporting
       During the quarter ended December 31, 2004,2005, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.
Item 9B.       Other Information
Disclosure Regarding Nominating Committee Functions and Communications Between Security Holders and Boards of Directors
      No change.
Rule 10b5-1 Plan Elections
      No rule 10b5-1 plans were adopted by executive officers or directors for the period that ended on December 31, 2004.      None.

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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 20052006 Annual Meeting of Stockholders and 20052006 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 20052006 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 2933 and 3034 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), Linnet F. Deily, Robert E. Denham, Franklyn G. Jenifer and Charles R. Shoemate, all of whom are independent under the New York Stock Exchange Corporate Governance Rules. Of these Audit Committee members, Linnet F. Deily, Robert E. Denham, Sam Ginn and Charles R. Shoemate are audit committee financial experts as determined by the Board within the applicable definition of the Securities and Exchange Commission.
      The information contained under the heading “Stock Ownership Information  –— Section 16(a) Beneficial Ownership Reporting Compliance” in the Notice of the 20052006 Annual Meeting of Stockholders and 20052006 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 20052006 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.
      The company has adopted a code of business conduct and ethics for directors, officers (including the company’s Chief Executive Officer, Chief Financial Officer and Comptroller) and employees, known as the Business Conduct and Ethics Code. The code is available on the company’s Internet Web site athttp://www.chevrontexaco.com/www.chevron.com/. Any amendments to the Business Conduct and Ethics Code will be posted on the company’scompany��s Web site.
Other Information
Item 11.Executive CompensationDisclosure Regarding Nominating Committee Functions and Communications Between Security Holders and Boards of Directors
      No change.
Rule 10b5-1 Plan Elections
      No Rule 10b5-1 plans were adopted for the period that ended on December 31, 2005.
Item 11.       Executive Compensation
      The information appearing under the headings “Executive Compensation” and “Directors Compensation” in the Notice of the 20052006 Annual Meeting of Stockholders and 20052006 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 20052006 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
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 20052006 Annual Meeting of Stockholders and 20052006 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 20052006 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.

37

      The information contained under the heading “Equity Compensation Plan Information” in the Notice of the 20052006 Annual Meeting of Stockholders and 20052006 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 20052006 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.
Item 13.       Certain Relationships and Related Transactions
Item 13.Certain Relationships and Related Transactions
      None.
Item 14.       Principal Accounting Fees and Services
      The information appearing under the heading “Board Operations – Certain Business Relationships Between ChevronTexacoheadings “Ratification of Independent Registered Public Accounting Firm — Principal Accountant Fees and its DirectorsServices” and Officers”“Ratification of Independent Registered Public Accounting Firm — Audit Committee Pre-Approval Policies and Procedures” in the Notice of the 20052006 Annual Meeting of Stockholders and 20052006 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 20052006 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.

3338

Item 14.Principal Accounting Fees and Services
      The information appearing under the headings “Ratification of Independent Registered Public Accounting Firm – Principal Accountant Fees and Services” and “Ratification of Independent Registered Public Accounting Firm – Audit Committee Pre-Approval Policies and Procedures” in the Notice of the 2005 Annual Meeting of Stockholders and 2005 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2005 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.
PART IV
Item 15.       Exhibits, Financial Statement Schedules
 (a) The following documents are filed as part of this report:
     (1)     Financial Statements:
   
  Page(s)
   
Report of Independent Registered Public Accounting Firm — PricewaterhouseCoopers LLP FS-24FS-28
 
Consolidated Statement of Income for the three years ended December 31, 20042005 FS-25FS-29
 
Consolidated Statement of Comprehensive Income for the three years ended December 31, 20042005 FS-26FS-30
 
Consolidated Balance Sheet at December 31, 20042005 and 20032004 FS-27FS-31
 
Consolidated Statement of Cash Flows for the three years ended December 31, 20042005 FS-28FS-32
 
Consolidated Statement of Stockholders’ Equity for the three years ended December 31, 20042005 FS-29FS-33
 
Notes to the Consolidated Financial Statements FS-30FS-34 to FS-55FS-62
     (2)     Financial Statement Schedules:
 We have included on page 3540 of this Annual Report on Form 10-K, Financial Statement Schedule II — Valuation and Qualifying Accounts.
 (3)     Exhibits:
 The Exhibit Index on pagesE-1 andE-2 of this Annual Report on Form 10-K lists the exhibits that are filed as part of this report.

3439

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars
                  
 Year Ended December 31 Year Ended December 31
    
 2004 2003 2002 2005 2004 2003
            
Employee Termination Benefits:
                    
Balance at January 1 $341 $336 $665  $137 $341 $336 
Additions charged to expense  29  295  71 
(Deductions) additions (credited) charged to expense  (21)  29  295 
Additions related to Unocal acquisition  106  —  — 
Payments  (233)  (290)  (400)  (131)  (233)  (290)
              
Balance at December 31
 $137 $341 $336  $91 $137 $341 
              
Allowance for Doubtful Accounts:
                    
Balance at January 1 $229 $225 $183  $219 $229 $225 
Additions charged to expense  36  52  131   3  36  52 
Additions related to Unocal acquisition  6  —  — 
Bad debt write-offs  (46)  (48)  (89)  (30)  (46)  (48)
              
Balance at December 31
 $219 $229 $225  $198 $219 $229 
              
Deferred Income Tax Valuation Allowance:*
                    
Balance at January 1 $1,553 $1,740 $1,512  $1,661 $1,553 $1,740 
Additions charged to deferred income tax expense  714  375  776   1,593  714  375 
Additions related to Unocal acquisition  400  —  — 
Deductions credited to goodwill  (60)  —  — 
Deductions credited to deferred income tax expense  (606)  (562)  (548)  (345)  (606)  (562)
              
Balance at December 31
 $1,661 $1,553 $1,740  $3,249 $1,661 $1,553 
              
* See also Note 1716 to the Consolidated Financial Statements beginning on page FS-42.FS-47.

3540

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 3rd1st day of March, 2005.2006.
 ChevronTexacoChevron Corporation
 By /s/David J. O’Reilly
  
 David J. O’Reilly, Chairman of the Board
 and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 3rd1st day of March, 2005.2006.
     
  Principal Executive Officers  
  (and Directors) Directors
 
  /s/David J. O’Reilly
David J. O’Reilly, Chairman of the Board and Chief Executive Officer		 Samuel H. Armacost*
Samuel H. Armacost
 
  /s/Peter J. Robertson
Peter J. Robertson, Vice Chairman
of the Board		Linnet F. Deily*
Linnet F. Deily
 Robert E. Denham*
Robert E. Denham
 
    Robert J. Eaton*
Robert J. Eaton
 
    Sam Ginn*
Sam Ginn
 
  Principal Financial Officer  
 
  /s/Stephen J. Crowe
Stephen J. Crowe, Vice President
Finance and Chief Financial Officer		 Carla A. Hills*
Carla A. Hills
 
    Franklyn G. Jenifer*
Franklyn G. Jenifer
 
  Principal Accounting Officer  
 
  /s/Mark A. Humphrey
Mark A. Humphrey, Vice President
and Comptroller		 J. Bennett Johnston*Sam Nunn*
J. Bennett JohnstonSam Nunn
 
    Sam Nunn*Donald B. Rice*
Sam NunnDonald B. Rice
 
  *By: /s/Lydia I. Beebe
        Lydia I. Beebe,
        Attorney-in-Fact		 Charles R. Shoemate*
Charles R. Shoemate
 
    Ronald D. Sugar*
Ronald D. Sugar
Carl Ware*
Carl Ware

3641

Index to Management’s Discussion and AnalysisINDEX TO MANAGEMENT’S DISCUSSION AND ANALYSIS,
Consolidated Financial Statements and Supplementary DataCONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

   
Management’s DiscussionPage No.
Key Financial Results
FS-2
Income From Continuing Operations by Major Operating Area
FS-2
Business Environment and Analysis of Financial Condition and Results of OperationsOutlook
 FS-2 to FS-5
Operating Developments
FS-5 to FS-7
Results of Operations
FS-7 to FS-11
Consolidated Statement of Income
FS-11 to FS-12
Selected Operating Data
FS-12
Information Related to Investment in Dynegy Inc.
FS-13
Liquidity and Capital Resources
FS-13 to FS-15
Financial Ratios
FS-15
Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies
FS-16 to FS-17
Financial and Derivative Instruments
FS-17 to FS-18
Transactions With Related Parties
FS-18
Litigation and Other Contingencies
FS-18 to FS-21
Environmental Matters
FS-21 to FS-22
Critical Accounting Estimates and Assumptions
FS-22 to FS-24
New Accounting Standards
FS-25
Quarterly Results and Stock Market Data
 FS-22FS-26
Report of Management
 FS-23FS-27
Reports
Report of Independent Registered Public Accounting Firm
FS-24
Consolidated Statement of IncomeFS-25
Consolidated Statement of Comprehensive IncomeFS-26
Consolidated Balance SheetFS-27
Consolidated Statement of Cash Flows FS-28
 
Consolidated Financial Statements
Consolidated Statement of Stockholders’ EquityIncome
 FS-29
Consolidated Statement of Comprehensive Income
FS-30
Consolidated Balance Sheet
FS-31
Consolidated Statement of Cash Flows
FS-32
Consolidated Statement of Stockholders’ Equity
FS-33
Notes to Consolidated Financial StatementsStatements:
 FS-30 to FS-55
 
Note 1.   Summary of Significant Accounting Policies
FS-34 to FS-36
Note 2.   Acquisition of Unocal Corporation
FS-36 to FS-37
Note 3.   Information Relating to the Consolidated Statement of Cash Flows
FS-37 to FS-38
Note 4.   Summarized Financial Data – Chevron U.S.A. Inc.
FS-38
Note 5.   Summarized Financial Data – Chevron Transport Corporation Ltd.
FS-38 to FS-39
Note 6.   Stockholders’ Equity
FS-39
Note 7.   Financial and Derivative Instruments
FS-39 to FS-40
Note 8.   Operating Segments and Geographic Data
FS-40 to FS-42
Note 9.   Litigation
FS-42
Note 10. Lease Commitments
FS-42 to FS-43
Note 11. Restructuring and Reorganization Costs
FS-43
Note 12. Assets Held for Sale and Discontinued Operations
FS-44
Note 13. Investments and Advances
FS-44 to FS-45
Note 14. Properties, Plant and Equipment
FS-46
Note 15. Accounting for Buy/Sell Contracts
FS-46 to FS-47
Note 16. Taxes
FS-47 to FS-48
Note 17. Short-term Debt
FS-48 to FS-49
Note 18. Long-term Debt
FS-49
Note 19. New Accounting Standards
FS-49
Note 20. Accounting for Suspended Exploratory Wells
FS-49 to FS-50
Note 21. Employee Benefit Plans
FS-50 to FS-54
Note 22. Stock Options and Other Share-Based Compensation
FS-54 to FS-56
Note 23. Other Contingencies and Commitments
FS-56 to FS-59
Note 24. Asset Retirement Obligations
FS-59 to FS-60
Note 25. Earnings Per Share
FS-61
Note 26. Common Stock Split
FS-62
Note 27. Other Financial Information
FS-62
Five-Year Financial Summary
 FS-57FS-64
Supplemental Information on Oil and Gas Producing Activities
 FS-57FS-65 to FS-68FS-78

FS-1

  
 Management’s Discussion and Analysis of Financial Condition and Results of Operations
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

KEY FINANCIAL RESULTS

                    
Millions of dollars, except per-share amounts 2004 2003 2002  2005 2004 2003 
       
Net Income $13,328   $7,230 $1,132  $14,099   $13,328 $7,230 
Per Share Amounts:*   
Per Share Amounts:   
Net Income – Basic $6.30   $3.48 $0.53  $6.58   $6.30 $3.48 
Net Income – Diluted
 $6.28   $3.48 $0.53 
– Diluted $6.54   $6.28 $3.48 
Dividends $1.53   $1.43 $1.40  $1.75   $1.53 $1.43 
Sales and Other Operating Revenues $150,865   $119,575 $98,340  $193,641   $150,865 $119,575 
Return on:      
Average Capital Employed  25.8%   15.7%  3.2%  21.9%   25.8%  15.7%
Average Stockholders’ Equity  32.7%   21.3%  3.5%  26.1%   32.7%  21.3%
      
*2003 and 2002 restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in 2004.

INCOME FROM CONTINUING OPERATIONS BY MAJOR OPERATING AREA

                    
Millions of dollars 2004 2003 2002  2005 2004 2003 
       
Income From Continuing Operations
      
Upstream – Exploration and Production      
United States $3,868   $3,160 $1,703  $4,168   $3,868 $3,160 
International 5,622   3,199 2,823  7,556   5,622 3,199 
       
Total Exploration and Production 9,490   6,359 4,526 
Total Upstream 11,724   9,490 6,359 
       
Downstream – Refining, Marketing and Transportation      
United States 1,261   482  (398) 980   1,261 482 
International 1,989   685 31  1,786   1,989 685 
       
Total Refining, Marketing and Transportation 3,250   1,167  (367)
Total Downstream 2,766   3,250 1,167 
       
Chemicals 314   69 86  298   314 69 
All Other  (20)   (213)  (3,143)  (689)   (20)  (213)
       
Income From Continuing Operations $13,034   $7,382 $1,102  $14,099   $13,034 $7,382 
Income From Discontinued Operations – Upstream 294   44 30  –   294 44 
       
Income Before Cumulative Effect of Changes in Accounting Principles
 $13,328   $7,426 $1,132  $14,099   $13,328 $7,426 
Cumulative Effect of Changes in Accounting Principles –    (196) –  –   –  (196)
       
Net Income*
 $13,328   $7,230 $1,132  $14,099   $13,328 $7,230 
     
*Includes Foreign Currency Effects:
 $(81) $(404) $(43) $(61) $(81) $(404)

     InNet income in 2003 net income included charges of $200a $196 million charge for the cumulative effect of changes in accounting principles,principle. The primary change related to the company’s adoption of Financial Accounting Standards Board (FASB) Statement No. 143, (FAS 143), “Accounting for Asset Retirement Obligations.Obligations,” Referwhich is discussed in Note 24 to Note 25 of the Consolidated Financial Statements on page FS-53 for additional discussion.

Statements. Net income in each period presented2004 included amounts for matters that management characterized as “special items,” as described ingains of approximately $1.2 billion relating to the table that follows. These amounts, becausesale of their nature and significance, are identified separatelynonstrategic upstream properties. Refer also to help explain the changes in net income and segment income between periods and to help distinguish the underlying trends for the company’s core businesses. Special items are discussed in detail for each major operating area in the “Results of Operations” section beginning on page FS-6. “Restructuring and Reorgani-
FS-7 for a detailed discussion of financial results by major operating area for the three years ending December 31, 2005.

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

SPECIAL ITEMS

              
Millions of dollars - Gains (charges) 2004   2003  2002 
    
Asset Dispositions             
Continuing Operations $960   $122  $– 
Discontinued Operations  257    –   – 
Litigation Provisions  (55)   –   (57)
Asset Impairments/Write-offs  –    (340)  (485)
Dynegy-Related  –    325   (2,306)
Tax Adjustments  –    118   60 
Restructuring and Reorganizations  –    (146)  – 
Environmental Remediation Provisions  –    (132)  (160)
Merger-Related Expenses  –    –   (386)
    
Total
 $1,162   $(53) $(3,334)
    

BUSINESS ENVIRONMENT AND OUTLOOK

As shown in the “Special Items” table, net special gains of $1.2 billion, associated mainly with the disposition of non-strategic upstream assets, benefited income in 2004. In 2002, $2.3 billion of the $3.3 billion of net charges related to theThe company’s investment in its Dynegy Inc. affiliate. Refer to page FS-11 for a discussion of the company’s investment in Dynegy.
     The special items recorded in 2002 through 2004 are not indicative of anycurrent and future trends of events or their impact on future earnings. Because of the nature of special item-related events, the company may not always be able to anticipate their occurrence or associated effects on income in any period. Apart from the effects of special-item gains and charges, the company’s earnings depend largely on the profitability of itsthe upstream – exploration(exploration and production –production) and downstream – refining,(refining, marketing and transportation –transportation) business segments. The single largest variablebiggest factor that affects the company’s results of operations for both segments is movement in the price of crude oil. In the downstream business, crude oil prices.is the largest cost component of refined products. Overall earnings trends are typically less affected by results from the company’s commodity chemicals segmentchemical business and other activities and investments. Earnings for the company in any period may also be affected by events or transactions that are infrequent and/or unusual in nature.
     The company’s long-term competitive position, particularly given the capital-intensive and commodity-based nature of the industry, is closely associated with the company’s ability to invest in projects that provide adequate financial returns and to manage operating expenses effectively. Creating and maintaining an inventory of projects depends on many factors, including obtaining rights to explore developfor crude oil and producenatural gas, developing and producing hydrocarbons in promising areas, drilling success, the ability to bring long-lead-timesuccessfully, bringing long-lead time capital-intensive projects to completion on budget and on schedule, and efficientoperating mature upstream properties efficiently and profitable operation of mature properties.profitably.
     The company also continuously evaluates opportunities to dispose of assets that are not key to providing sufficient long-term value, andor to acquire assets or operations complementary to its asset base to help sustainaugment the company’s growth. In addition to the asset-dispositionAsset-disposition and restructuring plans announced in 2003, which generated $3.7 billion of sales proceeds in 2004, other such plans may also occur in future periods and could result in significant gains or losses.
     In August 2005, the company acquired Unocal Corporation (Unocal), an independent oil and gas exploration and production company. The aggregate purchase price was $17.3 billion, which included $7.5 billion cash, approximately 169 million shares of Chevron common stock valued at $9.6 billion, and $0.2 billion for stock options on approximately 5 million shares and merger-related fees. Refer to the “Operating Developments” sectionNote 2, beginning on page FS-4FS-36, for a discussion that includes references toof the company’s asset disposition activities.Unocal acquisition.



FS-2

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

Upstream   Year-to-year changes in exploration and production earnings align mostEarnings for the upstream segment are closely aligned with industry price levels for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damagesdamage and disruptions, competing fuel prices, and regional supply interruptions that may be caused by military conflicts, civil unrest or political uncertainty.



FS-2

Moreover, any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments, and attempts to manage risks in operating its facilities and business. Longer-term trends in earnings
     Price levels for this segment are also a function of other factors besides price fluctuations, including changes in the company’s crude oilcapitalized costs and natural gas production levels and the company’s ability to find or acquire and efficiently produce crude oil and natural gas reserves.
     The level of operating expenses associated with the efficient production of crude oil and natural gas can also be subject to external factors beyond the company’s control. External factors include not only the general level of inflation but also prices charged by the industry’s product- and service-providers, which can be affected by the volatility of the industry’s own supply and demand conditions for such products and services. OperatingThe oil and gas industry

worldwide experienced significant price increases for these items during 2005 that are expected to continue into 2006. Capitalized costs and operating expenses can also be affected by uninsured damages to production facilities caused by severe weather or civil unrest.

     Industry price levels for crude oil reached record highs during 2004. For example, thecontinued an upward trend in 2005. The spot price for West Texas Intermediate (WTI) crude oil, one of the benchmark crudes, reached $55averaged $57 per barrel in October 2004. WTI prices for the full year averaged $41 per barrel,2005, an increase of approximately $10$16 per barrel from 2003.the 2004 average price. The WTI spot price for the first two months of 2006 averaged about $64 per barrel at the end of February 2005 was approximately $51. These relatively high industrybarrel. The rise in crude oil prices reflected,reflects, among other things, increasedincreasing demand from higher economic growth, particularly in Asia and the United States,growing economies, the heightened level of geopolitical uncertainty in manysome areas of the world crude oiland supply concerns in the Middle East and other key producing regions, andincluding production shut in for repairs following Hurricane Ivan in the Gulf of Mexico that partially was shut in September 2004.following the hurricanes.
     During most ofAs was the case in 2004, the differential in prices between high quality,high-quality, light-sweet crude oils, such as the U.S. benchmark

WTI, and the heavier crudes was unusually wide.wide in 2005. Chevron produces heavy crude oil in California, Chad, Indonesia, the Partitioned Neutral Zone (between Saudi Arabia and Kuwait), Venezuela (including volumes produced under an operating service agreement) and certain fields in Angola, China and the United Kingdom North Sea. The upward trend in prices in 2004 for lighter crude oils tracked the increased demand for light products, as all refineries could process these higher quality crudes. However, the demand and price for the heavier crudes werehas been dampened due tobecause of

ample supply, together with lower relative demand from the limited number of refineries that are able to process this lower quality feedstock.lower-quality feedstock into light-product fuels (i.e., motor gasoline, jet fuel, aviation gasoline and diesel fuel). The company producesdemand for heavy crude was further reduced in late 2005 as refining capacity along the U.S. Gulf Coast was interrupted by hurricanes. The price for higher-quality light oil, (including volumes under an operating service agreement) in California, Indonesia,on the Partitioned Neutral Zone (between Saudi Arabia and Kuwait) and Venezuela.other hand, has remained high, as the demand for light products, which can be manufactured by any refinery from light oil, has been robust worldwide.
     Natural gas prices, particularly in the United States, were also highertrended upward in 2004 than in 2003. Benchmark2005. For the full year, U.S. benchmark prices in 2004 forat Henry Hub U.S. natural gas peaked in October 2004 above $8.50averaged about $8 per thousand cubic feet (MCF). For the full year, prices averaged nearly $6.00 per MCF,, compared with $5.50about $6 in 2003. At the end of February 2005, the2004. Henry Hub spot price wasprices peaked in December 2005 above $14, as supplies early in the winter heating season were reduced by production shut in following Hurricanes Katrina and Rita. By mid-February 2006, prices had moved downward to about $6.10$8 per MCF.
     As compared with Fluctuations in the supply and demand factorsprice for natural gas in the United States are closely associated with the volumes produced in North America and the resultant trendinventory in underground storage to meet customer demand.
     In contrast to the Henry Hub benchmark prices,United States, certain other regions of the world in which the company operates have significantly different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices for the company’s production of natural gas. (Refer to the table on page FS-10FS-12 for the company’s average natural gas prices for the United StatesU.S. and international regions.) Additionally, excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the United States and other developed markets because of lack of infrastructure and the difficulties in transporting natural gas.
To help address this



FS-3

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

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



FS-3

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

significance of the overall investment in these long-term projects, the natural gas sales prices in the areas of excess supply (before the natural gas is transferred to a company-owned or third-party processing facility) are expected to remain well below sales prices for natural gas that is produced much nearer to areas of high demand and that can be transported in existing natural gas pipeline networks (as in the United States).
     Partially offsettingLonger-term trends in earnings for the benefitupstream segment are also a function of higherother factors besides price fluctuations, including changes in the company’s crude oil and natural gas prices in 2004 was a 5 percent decline inproduction 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. Investments in upstream projects generally are made well in advance of the start of the associated crude oil and natural gas production.
     Chevron’s worldwide net oil-equivalent production from the prior year,of approximately 2.5 million barrels per day in 2005, including volumes produced from oil sands and production under an operating service agreement. The decrease was largely the result of loweragreement, remained essentially unchanged from 2004. However, production in the United States duefourth quarter 2005 was nearly 2.7 million barrels per day, reflecting the benefit of volumes associated with the properties acquired from Unocal, the effect of which was partially offset by production shut in as a result of the hurricanes in the Gulf of Mexico. Prior to the hurricanes in August and September 2005, oil-equivalent production in the Gulf of Mexico was approximately 300,000 barrels per day. In 2006, production is projected to average approximately 200,000 barrels per day, as normal field declines property salesare expected to exceed the production being restored from wells that were shut in or damaged from the hurricanes and the production curtailments resultingthat will result from damagesthe drilling of new wells in the area. Approximately 20,000 net oil-equivalent barrels of daily production are not expected to producing operations caused by Hurricane Ivan. International oil-equivalent production was down marginally between years.be sufficiently economic to restore. Refer also to pages FS-711 through 24 for additional discussion and detail of production volumes worldwide.
     The level ofcompany estimates that oil-equivalent production in 2006 will average between 2.7 million and 2.8 million barrels per day. However, future periods is uncertain, in part becauseestimates are subject to many uncertainties, including quotas that may be imposed by OPEC, the price effect on production volumes calculated under cost-recovery and variable-royalty provisions of OPEC production quotascertain contracts, severe weather, and the potential for local civil unrest and changing geopolitics that could cause production
disruptions. Approximately 2526 percent of the company’s net oil-equivalent production in 2004,2005, including volumes producednet barrels from oil sands and production under an operating service agreement, wasoccurred in the OPEC-member countries of Indonesia, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. Although the company’s production level during 20042005 was not constrained in these areas by OPEC quotas, future production could be affected by OPEC-imposed limitations. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. Refer to pages FS-4FS-5 through FS-6FS-7 for discussion of the company’s major upstream projects.
     In certain onshore areas of Nigeria, approximately 45,000 barrels per day of the company’s net production capacity has beenwas shut in since Marchduring 2003 because of civil unrest and damage to production facilities. The company has adopted a phased plan to restore these operations, and has begun production-resumption efforts in certain areas.
     As a result of Hurricane Ivan in September 2004, production in the fourth quarter was about 60,000 barrels per day lower than it otherwise would have been. Damages to producing facilities are expected to restrict oil-equivalent production in the first quarter 2005 by approximately 35,000 barrels per day. Mostone-third of the remaining shut-involumes had been returned to production is expectedas of early 2006.
     Refer to be restored inpages FS-7 through FS-9 for additional discussion of the second quarter of 2005.company’s upstream operations.

     Downstream   Refining, marketing and transportation earnings are closely tied to global and 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 West Coast of North America, the U.S. Gulf Coast, Latin America, Asia and sub-Saharan Africa. In 2005, industry refining margins improved over the prior year, reflecting strong demand for refined products; however, marketing margins, which are highly influenced by regional market conditions, were mixed. Many regions experienced stronger marketing margins, but these margins were generally lower in the United States and Europe, as retail prices did not keep pace with rising crude oil and spot product prices. Industry margins in the future may be volatile, due primarily to changes in the price of crude oil used for refinery feedstock, disruptions at refineries resulting from maintenance programs and mishaps and levels of inventory and demand for refined products.

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

projects and operating incidents. The level of operating expenses for the downstream segment can also be affected by the volatility of charter expenses for the company’s shipping operations, which are driven by the industry’s demand for crude-oilcrude oil and product tankers. FactorsOther factors affecting the company’s downstream profitability that are beyond the



FS-4

company’s control include the general level of inflation especiallyand energy costs to operate the refinery network.
     Downstream earnings improved in 2004 compared with the prior year, primarily as a result of increased demand and higher marginsRefer to pages FS-9 through FS-10 for the industry’s refined products in mostadditional discussion of the areas in which the company and its equity affiliates havecompany’s downstream operations. In 2004, refined-product margins in North America and Asia were at their highest level in recent years. Industry margins may be volatile in the future, depending primarily on price movements for crude oil feedstocks, the demand for refined products, inventory levels, refinery maintenance and mishaps, and other factors.

     Chemicals   Earnings in the petrochemicals segmentbusiness are closely tied to global chemical demand, industry inventory levels and plant capacities.capacity utilization. Additionally, feedstock and fuel costs, which tend to follow crude oil and natural gas price movements, influence earnings in this segment.
     Earnings improved in 2004 compared with 2003 primarily from the resultsRefer to page FS-10 for additional discussion of chemical earnings for both the company’s Oronite subsidiary and the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate, which recorded higher margins and sales volumes for commodity chemicals and higher equity affiliate income.LLC.

OPERATING DEVELOPMENTS

Key operating developments and other events during 20042005 and early 20052006 included:

Upstream

Worldwide Proved ReservesAs a result of the acquisition of Unocal in August 2005, the company increased its net oil-equivalent proved reserves by approximately 1.5 billion barrels. Significant unproved volumes of oil and

gas were also added to the company’s resource base. (Refer to pages FS-70 through FS-75 for a detailed discussion of proved reserve changes for 2005 and Note 2 beginning on page FS-36 for a discussion of the Unocal acquisition.)
North America   During 2004,In September 2005, the company closedsold Northrock Resources Limited, a wholly owned Canadian subsidiary of Unocal, for $1.7 billion. The disposition was consistent with Chevron’s divestiture in 2004 of its conventional crude oil and natural gas business in Western Canada, enabling the company’s continued focus on the saleprofitable growth of more thanproduction of crude oil and natural gas in strategically important core areas of operation.
300 producing properties and other assets     In late 2005, the company began construction of the floating production facility to be installed in the United StatesTahiti Field, in the deepwater Gulf of Mexico. Tahiti is anticipated to have a maximum total daily production of 125,000 barrels per day of crude oil and Canada, generating proceeds70 million cubic feet of $2.5 billion. These sales, which accounted for less than 10natural gas. Chevron is the operator and holds a 58 percent working interest in the project that is being developed in phases and expected to come onto production in 2008.

     In the same period, the decision was made to proceed with the development of the oil-equivalentBlind Faith Field, also in the deepwater Gulf of Mexico. First production is expected in 2008, with initial total daily output estimated at 30,000 barrels of crude oil and reserves30 million cubic feet of natural gas. Chevron is the operator and holds a 62.5 percent working interest in North America, were part of plans announced in 2003 to dispose of assets that did not provide sufficient long-term value tothe project.
     In late 2005, the company and to improve the overall competitive performance and operating efficiency of the company’s exploration and production portfolio.
     Indrilled deepwater crude oil discoveries in the Gulf of Mexico at the company awarded two major engineering contracts for the development of subsea systems60 percent-owned and a floating production facility to advance the development of the operated and 58 percent-owned TahitiBig Foot prospect a major deepwater discovery. A successful well test of the original discovery well was also conducted in 2004. Elsewhere in the





FS-4

Gulf of Mexico, a deepwater crude oil discovery was announced at the operated and 50 percent-owned Jack prospect in Walker Ridge Block 759.29 and the 25 percent-owned, nonoperated Knotty Head prospect located in Green Canyon Block 512. Additional appraisal activity continued into 2006 at both locations.
     Angola   In late 2004,early 2006, first productionoil was achieved atproduced from the Block 0 Sanha Bomboco project, which will help reduce natural-gas flaring.
Australia In mid-2004, the company announced a natural gas discovery at the wholly owned Wheatstone-1 well located offshore Western Australia. Production tests were completed in the third quarter 2004, and in early 2005 the company was evaluating development options.
Cambodia In January 2005, the company announced crude oil discoveries at four exploration wells in offshore Block A. ChevronTexaco is the operator of the block and holds a 55 percent interest.
China In August 2004, initial crude oil production occurred at the 16 percent-owned BZ 25-1 Field, located in Bohai Bay. Crude oil production also began late in 2004 at the HZ 19-331 percent-interest deepwater Belize Field in which the company hasBlock 14, offshore Angola. The Benguela, Belize, Lobito and Tomboco fields form a 33 percent working interest.
Faroe Islands In January 2005, the company was awarded five offshore exploration blocksproject that is being developed in the Faroe Islands’ second offshore licensing round.two phases. The blocks are near the earlier Rosebank/Lochnagar discovery in the United Kingdom. The company has a 40 percent interest and will be the operator.
Kazakhstan The company’s first crude oil from Karachaganak Field was loaded at Russia’s Black Sea port of Novorossiysk in mid-2004. This represented the first shipment of Karachaganak crude oil through the Caspian Pipeline Consortium export pipeline that provides access to world markets.
     Construction continued during 2004 by the company’s 50 percent-owned Tengizchevroil affiliate on Sour Gas Injection (SGI)/Second Generation Project (SGP), which is expected to increasemaximum total production from both phases of the current capacity of 298,000project is anticipated to reach 200,000 barrels of crude oil per day in 2008.
Australia   In mid-2005, the company won exploration rights to between 430,000four deepwater blocks in the northern Carnarvon Basin offshore Western Australia. In early 2006, the company was awarded rights to another block in the Carnarvon Basin. The blocks are located in an area of significant natural gas potential and 500,000near the Chevron-led Gorgon Project. Chevron holds a 50 percent operated interest in the blocks.
Kazakhstan   In late 2005, the company’s 50 percent-owned Tengizchevroil (TCO) affiliate awarded commercial contracts to enable increased crude-oil exports through a southern route across the Caspian Sea. The southern route will provide additional export capacity for TCO’s increased production until the Caspian Pipeline Consortium pipeline is expanded. The additional crude oil production at TCO will result from major facilities-expansion projects being constructed at a total cost of approximately $5.5 billion. By the third quarter 2007, TCO’s crude production capacity is projected to increase from the current capacity of 300,000 barrels per day by the end of 2006, with the expansion dependent upon the success of the SGI.to between 460,000 and 550,000.
     LibyaNigeria   In early 2005, the companya construction contract was awarded onshore Block 177 in Libya’s first exploration license round under the Exploration and Production Sharing Agreement IV terms. The company was also made operator of the block with 100 percent equity. The events mark the company’s return to Libya after a 28-year absence.
Nigeria At the deepwater Agbami project, several milestones were achieved in 2004, including initial development drilling in the third quarter, and reaching a unitization agreement with other owners in the area. In early 2005, a contract for the construction of a$1.1 billion floating production, storage and offshore loading platformoffloading (FPSO) vessel to be used at the Agbami Field. The construction contract was awarded. The project is being unitized, and the company’s equity will be about 68 percent.
     The company was awarded a 100 percent contractor interestkey milestone in the deepwater Nigeria Block OPL-247 in the eastern partdevelopment of the Niger Delta68 percent-owned Agbami Field, which is scheduled to come online in the second quarter 2004. Block 247 is adjacent to Block 222, which includes the company’s Usan and Ukot discoveries.
     In the third quarter 2004, the company announced a2008 with an estimated maximum total daily production of 250,000 barrels of crude oil discovery at the Usan 5 well. Additionally, in early 2005, hydrocarbons were encountered at the Usan 6 appraisal well. ChevronTexaco holds a 30 percent interest in the wells, both of which are located in OPL-222.oil.
     Nigeria — São Tomé ande Príncipe Joint Development Zone (JDZ) The company was awarded the right in early 2004 to conduct exploration activities in deepwater Block 1 in the JDZ, offshore São Tomé and Príncipe and Nigeria.   In early 2005, the company signed a production-sharing contract withfor Block 1 in the Joint
Development Authority, under which ChevronTexacoNigeria - São Tomé e Príncipe JDZ. Chevron will be the operator withand has a 51 percent interest in the block.
Southern Africa The company announced a discovery in Drilling of the deepwater area between Angola and the Republic of Congo at the Lianzi-1first exploration well was under way in the third quarter 2004. The discovery, in the shared 14K/A-IMI Unit, is located in the same area as the previous Block 14 deepwater crude oil discoveries at Landana and Tombua in Angola. ChevronTexaco is the operator of the 14K/A-IMI Unit and holds about a 31 percent interest.
Russia In September 2004, the company and OAO Gazprom signed a six-month memorandum of understanding to jointly undertake feasibility studies for the possible implementation of projects in Russia and the United States. This represents a possible opportunity to participate in the development of the vast natural gas and crude oil resource base in Russia and to develop a close partnership with Russia’s largest natural gas producer.
Thailand The company announced successful exploration and appraisal drilling results in mid-2004 at Block G4/43, located in the Gulf of Thailand. Block G4/43 is adjacent to the company’s operated and 52 percent-owned Block B8/32.
Trinidad and Tobago In early 2005, the company announced successful exploration drilling results at the offshore Manatee 1 exploration well in Block 6d. ChevronTexaco operates and holds a 50 percent interest in this well.
United Kingdom In the third quarter 2004, production of first crude oil occurred at the 21 percent-owned Alba Extreme South Phase 2 project. Alba Field is located in Block 16/26, northeast of Aberdeen. In the fourth quarter, a crude oil and natural gas discovery was made at the offshore 40 percent-owned Rosebank/Lochnagar well (213/27-1Z) in the Faroe-Shetland Channel.late-February 2006.
     Venezuela   In August 2004, the company was awarded an exploration license and 100 percent interest for Block 3 in Plataforma Deltana, an offshore area on Venezuela’s Atlantic continental shelf. The exploration rights added to the company’s existing Block 2 license in Venezuela and Block 6d in Trinidad and Tobago, across the border with Venezuela. Two exploration wells were successful during 2004 in the operated and 60 percent-owned Plataforma Deltana Block 2.
     The company completed onshore construction of the 30 percent-owned Hamaca Project’s crude oil upgrading facility. This facility has the capacity to process 190,000 barrels per day of heavy crude oil and upgrade into 180,000 barrels per day of lighter higher-value crude oil. Upgrading began in October 2004.
Global Natural Gas ProjectsIn Qatar, Sasol Chevron, ChevronTexaco’s 50-50 global joint venture with Sasol of South Africa, entered into a memorandum of understanding with Qatar Petroleum to expand the Oryx gas-to-liquids project and a letter of intent to examine GTL base oils opportunities in Qatar. Qatar Petroleum and Sasol Chevron also agreed to pursue an opportunity to develop a 130,000-barrel-per-day integrated gas-to-liquids project.
     In Australia, the North West Shelf Venture began commissioning of a fourth LNG train in September 2004. This increased the venture’s LNG production capacity by approximately 50 percent during 2004. ChevronTexaco holds a one-sixth interest in the joint venture.
     The company announced in the fourth quarter 2004 an agreement with other shareholders of the West African Gas Pipeline Co. Ltd. to move forward with the construction of a pipeline to be used for the transportation of natural gas more than 400 miles from Nigeria to customers in Ghana, Benin and Togo.
     In earlyJune 2005, the company announced plans to conductdiscovered natural gas in Block 3 of Plataforma Deltana, offshore Venezuela. The site is in the proximity of the Loran natural gas field in Block 2 and provides sufficient resources for a feasibility study on a potentialdetailed evaluation of Venezuela’s first liquefied natural gas (LNG) project at Olokola in southwest Nigeria. Future decisions to movetrain.


FS-5

  
 Management’s Discussion and Analysis of Financial Condition and Results of Operations
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

forward     In the third quarter 2005, the company was awarded an exploration license for the Cardon III Block, offshore western Venezuela. The block is in a region with Olokola LNGnatural gas potential to the north of the Maracaibo producing area.
     In December 2005, Chevron signed a transition agreement with Petróleos de Venezuela, S.A. (PDVSA), the Venezuelan state-owned petroleum company, to convert contracts for the Boscan and LL-652 operating service agreements into an Empresa Mixta (EM). The EM is a joint-stock contractual structure with PDVSA as the majority shareholder. Negotiation of the ownership and format of the final EM structure will dependbe conducted during 2006. Possible financial implications of the EM structure are uncertain, but are not expected to have a material effect on the results ofcompany’s consolidated financial position or liquidity.
Global Natural Gas Projects   In Angola, the feasibility study.
     In November 2004, ChevronTexaco and its partnerscompany awarded contracts in the Brass LNG Project awarded the contractApril 2005 for front-end engineering and design studies for a world-scalemulti-billion-dollar onshore LNG plant to beproject located in Nigeria. The LNG plantnorthern Angola. This project will have two processing trains with potential processing capacitybe designed to help reduce flaring of 5 million metric tons each. ChevronTexaco is expected to supplynatural gas and represents a major amountstep toward the commercialization of feed gas to the LNG project.
     In Angola, front-end engineering and design work is scheduled to begin in the first halfsome of 2005 for the construction of a multibillion dollar LNG processing plant that also will help eliminateAngola’s vast natural gas flaring associated with crude oil producing operations.resources. The company has a 36 percent ownership interest in the plantAngola LNG project and will co-lead the projectdevelopment with the Angolan government’s national oil company. Construction is expected to begin in 2007.
     In September 2004,April 2005, the company was awarded authorization fromreached an agreement with joint-venture participants in the Mexican Environment and Natural Resources Secretariat for its Environmental Impact Assessment and Risk Assessment for a proposed LNG receiving and regasification terminalGreater Gorgon Area, offshore Baja California, Mexico. In December 2004,western Australia that will enable the company was awarded acombined development of natural gas storage permit from the Mexican Regulatory Energy Commission for a proposed naturalat Gorgon and nearby gas terminal.fields as one project. The company also received notice fromis a significant holder of gas resources in the Mexican Communicationarea and Transport Secretariat, through its Port Authority, that it wonwill have an approximate 50 percent ownership interest across most of the public licensing round for the offshore port terminal.Greater Gorgon Area.
     In November 2004, the company announced it had plans to submit permit applications for a proposed LNG import terminal to be located at the company’s Pascagoula Refinery.
     In December 2004,June 2005, the company announced the finalizationdecision to move the Australian Greater Gorgon gas development project into the front-end engineering and design phase for a two-train (10 million metric tons per year) LNG facility and a potential domestic gas plant on Barrow Island, targeting initial production by 2010. Chevron is the operator and has a 50 percent ownership interest in the licenses for the Greater Gorgon Area.
     In the fourth quarter 2005, the company signed a Heads of Agreement (HOA) for first sale of LNG from the Gorgon Project into Japan, the world’s largest LNG market. The preliminary agreement was signed by Chevron Australia Pty Ltd with Tokyo Gas Co. Ltd, a 20-yearmajor Japanese utility company, for the purchase of 1.2 million metric tons per year of Gorgon LNG over 25 years. Two additional HOAs were later signed by Chevron Australia Pty Ltd with Chubu Electric Co. Inc and Osaka Gas Co. Ltd, both companies from Japan. Each preliminary agreement was for regasificationthe purchase of 1.5 million metric tons per year of Gorgon LNG over 25 years commencing in 2010 and 2011, respectively.
     The company and its partners in the North West Shelf (NWS) venture agreed in mid-2005 to expand the project’s onshore LNG facilities in Western Australia. Chevron holds a one-sixth interest in the NWS venture. The $1.5 billion project includes adding a fifth train that will increase LNG export capacity by more than 4 million metric tons per year to approximately 16 million metric tons per year, with startup expected in 2008. In December 2005, the NWS joint venture participants approved development of the Angel natural gas field, which will provide the natural gas supply for the Train 5 expansion.
     In Nigeria, the company awarded a $1.7 billion contract in April 2005 for the engineering, procurement and construction of the Escravos gas-to-liquids project. Plant construction began in 2005 including major equipment fabrication and site preparation.
     In the third quarter 2005, installation began on a 350-mile main offshore segment of the West African Gas Pipeline that will provide natural gas to markets in Ghana, Togo and Benin by connecting to an existing onshore pipeline in Nigeria. The pipeline will have a capacity of approximately 475 million cubic feet per day and will help in the reduction of the flaring of natural gas in the company’s areas of operation.
     In Russia, OAO Gazprom has included Chevron on a list of companies that could continue further commercial and technical discussions concerning the development and related commercial activities of the Shtokmanovskoye Field. Discussions were under way in early 2006, but the timing of Gazprom’s selection of the company or companies that will participate in the field development was uncertain. Shtokmanovskoye is a very large natural gas field offshore Russia in the Barents Sea. OAO Gazprom is Russia’s largest natural gas producer.
     In the United States, Chevron completed the acquisition of the remaining 40 percent interest of Bridgeline Holdings, L.P. in August 2005. Bridgeline manages and operates more than 1,000 miles of pipeline and 12 billion cubic feet of natural gas storage capacity in southern Louisiana.
     In the third quarter 2005, the company filed an application with the Federal Energy Regulatory Commission to own, construct and operate a natural gas import terminal at the proposedCasotte Landing site adjacent to Chevron’s refinery in Pascagoula, Mississippi. The terminal will be designed to initially process 1.3 billion cubic feet of natural gas per day from imported LNG.
     In the fourth quarter 2005, the company committed to pipeline and additional LNG terminal capacity in the Sabine Pass area of Louisiana. The first commitment was for 1 billion cubic feet per day of pipeline capacity in a new pipeline and additional interconnect capacity to an existing pipeline. The company also exercised its option to increase capacity at


FS-6

a Sabine Pass LNG terminal in Louisiana.from 700 million to 1 billion cubic feet per day.

Downstream

Worldwide ReorganizationUnited States   In early 2004,The company initiated a project to increase the company’s downstream businesses began operating as global refining, marketing,capacity of the Pascagoula, Mississippi, refinery’s fluid catalytic cracking unit by approximately 25 percent, from a current capacity of 63,000 barrels per day. This project is designed to enable the refinery to increase its production of gasoline and supplyother light products and trading businesses. Previously, these functions were aligned by the individual geographic areas in which the company operates. This realignment is targeted to improve operating efficiencies and financial performance.
Singapore Joint Venture In July 2004, the company acquired an additional interest in the Singapore Refining Company Pte. Ltd. (SRC), increasing its ownership from 33 percent to 50 percent. This additional interest in SRC is expected to strengthen ChevronTexaco’s existing strategic position in the Asia-Pacific area, one of its core markets.be completed by late 2006.
     China Joint Venture In January 2005, the company announced a preliminary agreement for a business partner in China to take a majority interest in the company’s existing joint venture that operates retail service stations in South China.
Asset Dispositions Throughout 2004, the company continued the marketing and sale of service station sites. Dispositions of about 1,600 sites occurred from the program’s inception in early 2003 through the end of 2004. In February 2005, the company announced a memorandum of understanding to negotiate the sale of approximately 140 service stations in the United Kingdom.
Texaco Brand Under terms of an agreement executed at the time of the merger with Texaco, the company regained non-

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

Chemicals

Saudi ArabiaKorea   The company’s 50 percent-owned GS Caltex affiliate CPChem, began constructionannounced a major upgrade project at its 650,000-barrel-per-day Yeosu refining complex. At an estimated total cost of an integrated styrene facility$1.5 billion, the facilities will increase the yield of high-value refined products and expansionreduce feedstock costs through the processing of an adjacent aromaticsheavy crude oil. Start-up is expected by the end of 2007.

Chemicals

QatarThe company’s 50 percent-owned affiliate, Chevron Phillips Chemical Company LLC (CPChem), has obtained approvals and completed the financial closing for the Q-Chem II complex to be located next to the existing Q-Chem I complex in Mesaieed, Qatar. The Q-Chem II complex will include a 350,000-metric-ton-per-year polyethylene plant at Al Jubail, Saudi Arabia, in the fourth quarter 2004.and a 345,000-metric-ton-per-year normal alpha olefins plant. The project is scheduled for completionalso includes a separate joint venture to develop a 1,300,000-metric-ton-per-year ethylene cracker at Qatar’s Ras Laffan Industrial City. CPChem and its partners expect to start-up the cracker and derivatives plants in the first halflate 2008. CPChem owns a 49 percent interest of 2008.Q-Chem II.

Other

Common Stock Dividends and Stock Repurchase Program   In September 2004,April 2005, the company increased its quarterly common stock dividend by 1012.5 percent and immediately followed the dividend increase withto $0.45 per share. The company completed an authorized $5 billion of stock buybacks in November 2005 under a two-for-one stock split in the form of a stock dividend. In connection with a stock repurchase program initiated in April 2004,2004. Upon completion of this program, the company purchased 42,324,000 shares inthen authorized the open market for $2.1 billion through December. Purchases through the end of February 2005 increased the total shares acquired to 47,969,000 shares for $2.4 billion. The repurchase program is in effect for up to three years from the date initiated for acquisitionsacquisition of up to $5 billion.billion of additional shares over a period of up to three years. Purchases under this authorization totaled $481 million through mid-February 2006.

RESULTS OF OPERATIONS

Major Operating Areas   The following section presents the results of operations for the company’s business segments – upstream, downstream and chemicals – as well as for “all other,” which includes mining operations of coal and other minerals, power generation businesses, and the various companies and departments and companiesthat are managed at the corporate level. Income is also presented for the U.S. and international geographic areas of the upstream and downstream business segments. (Refer to Note 98, beginning on page FS-36FS-40, for a discussion of the company’s “reportable segments,” as defined in FAS 131,“Disclosures About Segments of an Enterprise and Related Information.”))

     To aid in the understanding of changes in segment income between periods, the discussion, when applicable, is in two parts – first on underlying trends, and second on special-item gains and charges that tendedcharges. The special items are identified separately because of their nature and amount and also to obscure these trends. Inhelp discern the following discussions,underlying trends for the term “earnings” is defined as net income or segment income before the cumulative effect of changes in accounting principles.company’s businesses. This section should also be read in conjunction with the discussion of the company’sin “Business Environment and Outlook” on pages FS-2 through FS-4.FS-5.

U.S. Upstream – Exploration and Production

                    
Millions of dollars 2004 2003 2002  2005 2004 2003 
       
Income From Continuing Operations $3,868   $3,160 $1,703  $4,168   $3,868 $3,160 
Income From Discontinued Operations 70   23 14  –   70 23 
Cumulative Effect of Accounting Change –    (350) –  –   –  (350)
       
Segment Income*
 $3,938   $2,833 $1,717 
Total Income*
 $4,168   $3,938 $2,833 
       
*Includes Special-Item Gains (Charges):      
   
Asset Dispositions      
Continuing Operations $316   $77 $–  $–   $316 $77 
Discontinued Operations 50   – –  –   50 – 
Litigation Provisions  (55)  – –  –    (55) – 
Asset Impairments/Write-offs –    (103)  (183) –   –  (103)
Restructuring and Reorganizations –    (38) –  –   –  (38)
Environmental Remediation Provisions –   –  (31)
       
Total $311   $(64) $(214) $–   $311 $(64)
      



FS-6

     U.S. upstream income of nearly $4.2 billion in 2005 increased $230 million. The amount in 2004 included net special-item benefits (discussed below) of more than $300 million. Higher prices for crude oil and natural gas in 2005 and earnings from the former Unocal operations contributed approximately $2 billion to the increase between periods. Approximately 90 percent of this amount related to the effects of higher prices on heritage-Chevron production. These benefits were partially offset by the adverse effects of lower production (discussed below), higher operating expenses and higher depreciation expense associated with heritage-Chevron properties.
     Income from continuing operationsof $3.9 billion in 2004 of nearly $3.9was $1.1 billion was about $700 million higher than the $2.8 billion recorded in 2003. Nearly $400Of this increase, $725 million of the increase representedresulted from the difference in the effect on earnings in the respective periods from special items which are discussed below.and the cumulative-effect charges recorded in 2003 for the implementation of a new accounting standard. (Refer to Note 24, beginning on page FS-59, for a discussion of FAS 143,“Accounting for Asset Retirement Obligations.”) The remaining $300 million improvementbalance of the increase from 2003 to 2004 was composed of about a $1 billion benefit from higher prices for crude oil and natural gas prices that was largely offset by the effects of lower production.
     Income from continuing operations in 2003 was about $3.2 billion, up approximately $1.5 billion from 2002. The benefit of higher prices between periods was about $1.7 billion and was partially offset by the effect of lower production.
     The company’s average realization for crude oil and natural gas liquids realization in 20042005 was $34.12$46.97 per barrel, compared with $34.12 in 2004 and $26.66 in 2003 and $21.34 in 2002.2003. The average natural gas realization was $5.51$7.43 per thousand cubic feet in 2004,2005, compared with $5.51 and $5.01 in 2004 and $2.89 in 2003, and 2002, respectively.
     Net oil-equivalent production in 2005 averaged 817,000727,000 barrels per day, in 2004, down 1211 percent from 20032004 and 1922 percent from 2002.2003. The decline between 2004 and 2005 was the result of the effects of hurricanes, property sales and normal field declines, which were partially offset by the benefit of



FS-7

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

five months of production in 2005 from properties acquired from Unocal. The lower production inbetween 2003 and 2004 included the effects of about 30,000 barrels per daywas associated with property sales, and 21,000 barrels per day of production shut in as a result of damages to facilities from Hurricane Ivan in the third quarter. Adjusting for the effects of property salesstorms and storms in all periods presented, oil-equivalent production in 2004 declined about 7 percent from 2003 and 14 percent from 2002, mainly as a result of normal field declines that do not typically reverse.declines.
     The net liquids component of oil-equivalent production for 20042005 averaged 505,000455,000 barrels per day, a decline of 10 percent from 20032004 and 1619 percent from 2002. Excluding2003. Absent the effects of the Unocal volumes in 2005, property sales and storms, net liquids production in 20042005 declined 56 percent and 11 percent from 20032004 and 2002,2003, respectively.
     Net natural gas production averaged 1.91.6 billion cubic feet per day in 2005, down 13 percent and 27 percent from 2004 16 percent lower thanand 2003, and 22 percent lower than 2002. Adjusting forrespectively. Excluding the Unocal volumes in 2005, the effects of property sales and shut-in production related to storms, 2004 net natural gas production in 2005 declined 10 percent in 2003from 2004 and 1720 percent in 2002.from 2003.
     Refer to the “Selected Operating Data” table, on page FS-10FS-12, for the three-year comparative production volumes in the United States.

     Segment incomeNo special items were recorded in 2005. Special items in 2004 included special gains of $366 million from property sales, partially offset by special charges of $55 million resulting fromdue to an adverse litigation matter. Net special charges of $64 million in 2003 were composed of charges of $103 million for asset impairments, associated mainly with the write-down of assets in anticipation of sale; charges of $38 million for restructuring and reorganization, mainly for employee severance costs; and gains of $77 million from property sales. Special charges in 2002 totaled $214 million, which included $183 million for the impairment of a number of fields caused by the write-down of proved reserves and $31 million for costs of environmental remediation.

International Upstream – Exploration and Production

              
Millions of dollars 2005   2004  2003 
    
Income From Continuing Operations1
 $7,556   $5,622  $3,199 
Income From Discontinued Operations  –    224   21 
Cumulative Effect of Accounting Change  –    –   145 
    
Total Income2
 $7,556   $5,846  $3,365 
    
1 Includes Foreign Currency Effects:
  $14    $(129)   $(319) 
2 Includes Special-Item Gains (Charges):
             
Asset Dispositions             
Continuing Operations $–   $644  $32 
Discontinued Operations  –    207   – 
Asset Impairments/Write-offs  –    –   (30)
Restructuring and Reorganizations  –    –   (22)
Tax Adjustments  –    –   118 
    
Total $–   $851  $98 
    
              
Millions of dollars 2004   2003  2002 
    
Income From Continuing Operations1
 $5,622   $3,199  $2,823 
Income From Discontinued Operations  224    21   16 
Cumulative Effect of Accounting Change  –    145   – 
    
Segment Income2
 $5,846   $3,365  $2,839 
    
1Includes Foreign Currency Effects:
 $(129)  $(319) $90 
2 Includes Special-Item Gains (Charges):
             
Asset Dispositions             
Continuing Operations $644   $32  $– 
Discontinued Operations  207    –   – 
Asset Impairments/Write-offs  –    (30)  (100)
Restructuring and Reorganizations  –    (22)  – 
Tax Adjustments  –    118   (37)
    
Total $851   $98  $(137)
    

     International upstream income of more than $7.5 billion in 2005 increased $1.7 billion from $5.8 billion in 2004. Higher prices for crude oil and natural gas in 2005 and earnings from the former Unocal operations increased earnings approximately $2.9 billion between periods. About 80 percent of this benefit arose from the effect of higher prices on heritage-Chevron production. Partially offsetting these benefits were higher expenses between periods for heritage-Chevron operations for certain income-tax items, including the absence of a $200 million benefit in 2004 relating to changes in income tax laws. The change between years also reflected the impact of $851 million of special-item gains in 2004, while no special items were recorded in 2005. Foreign currency losses in 2004 were $129 million. Gains of $14 million were recorded in 2005.

Income from continuing operations of $5.6$5.8 billion in 2004 increased about $2.4was nearly $2.5 billion higher than earnings recorded in 2003. Approximately $900 million of the increase was the difference between the effects in each period from 2003.special items (discussed below) and foreign currency losses. Approximately $1.1 billion of the increase was associated with higher prices for crude oil and natural gas. Approximately $750 million of the increase was the result of the effects of special items in each period, which are discussed below. Another $400 million resulted from lower income-tax expense between periods, including a benefit of about $200 million in 2004 as a result of changes in income tax laws. Otherwise, the benefitPartially offsetting these effects were higher transportation costs in 2006 of about $200 million in lower foreign currency lossesmillion. The balance of the change between periods was largely offset by higher transportation costs.
     Income from continuing operations of $3.2 billionassociated with a gain in 2003 was nearly $400 million higher than in 2002. Higher crude oil and natural gas prices accounted for an increase of about $900 million, which was partially offset by $400 million from the effectimplementation of foreign currency changes and about $100 milliona new accounting standard. (Refer to Note 24, beginning on page FS-59, for a discussion of higher income tax-expense.FAS 143,“Accounting for Asset Retirement Obligations.”)
     Net oil-equivalent production of 1.71.8 million barrels per day in 2004 –2005, including other produced volumes of 140,000143,000 net barrels per day from oil sands in Canada and production under an operating service agreement – declinedin Venezuela, increased about 16 percent from 20032004 and 25 percent from 2002. Excluding2003. Absent the lowernet effect of increased volumes in 2005 from five months of production associated withfrom the former Unocal operations, the effect of property



FS-8

sales and reduced volumes associated withthe effect of higher prices on cost-recovery and variable-royalty provisions of certain production-sharing agreements, 2004 net oil-equivalent production increased nearly 3 percent from 2003 and 1 percent from 2002 – primarily from highercontracts, oil-equivalent production in Chad, Kazakhstan2005 was essentially the same as 2004 and Venezuela.2003.
     The net liquids component of oil-equivalent production including volumes producedwas 1.4 million barrels per day in 2005, unchanged from oil sands2004 and under an operating service agreement, declined about 1 percent from the production level in 2003 and about 3 percent from 2002.2003. Excluding the effects of Unocal production, property sales and lowerthe effect of higher prices on cost-recovery and variable-royalty volumes, under certain production-sharing agreements, 20042005 net liquids



FS-7

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

production increased aboutwas essentially the same as 2004 and decreased 1 percent from 20032003.
     Net natural gas production of 2.6 billion cubic feet per day in 2005 was up 25 percent and decreased about 126 percent from 2002.
     The net natural gas component2004 and 2003, respectively. Excluding the effect of oil-equivalent production was up 1from the Unocal properties, production increased 2 percent and 3 percent from 2004 and 2003, and 6 percent from 2002. During 2004, production increases in Angola, Kazakhstan, Denmark and Australia were partially offset by declines associated with asset sales. In 2003, areas with production increases included Australia, Kazakhstan, the Philippines and the United Kingdom.respectively.
     Refer to the “Selected Operating Data” table, on page FS-10FS-12, for the three-year comparative of international production volumes.
     No special items were recorded in 2005. Special-item gains in 2004 included $585 million from the sale of producing properties in westernWestern Canada and $266 million from the sale of other nonstrategic assets, including the company’s operations in the Democratic Republic of the Congo and a Canadian natural-gas processing business. In 2003, net specialspecial-item gains of $98 million included benefits of $150 million related to income taxes and property sales, partially offset by asset impairments in advance of sale and charges for employee termination costs. In 2002, special charges of $137 million included $100 million for asset impairments resulting from the write-down of proved reserves for fields in Africa and Canada.

U.S. Downstream – Refining, Marketing and Transportation

              
Millions of dollars 2005   2004  2003 
    
Income*
 $980   $1,261  $482 
    
*Includes Special-Item Gains (Charges):             
Asset Dispositions $–   $–  $37 
Environmental Remediation Provisions  –    –   (132)
Restructuring and Reorganizations  –    –   (28)
    
Total $–   $–  $(123)
    
              
Millions of dollars 2004   2003  2002 
    
Segment Income (Loss)*
 $1,261   $482  $(398)
    
*Includes Special-Item Gains (Charges):             
Asset Dispositions $–   $37  $– 
Asset Impairments/Write-offs  –    –   (66)
Environmental Remediation Provisions  –    (132)  (92)
Restructuring and Reorganizations  –    (28)  – 
Litigation Provisions  –    –   (57)
    
Total $–   $(123) $(215)
    

     The     U.S. downstream earnings improvementof nearly $1 billion in 2005 decreased about $300 million from 2004 and were up $500 million from 2003. Results in 2003 included net special-item charges (discussed below) of $123 million. Average refined-product margins in 2005 were higher than in 2004, from both 2003 and 2002 was associated mainly with higher margins for refined products. Margins in 2004 were significantly higher than in 2003. However, the highesteffects of increased downtime at refineries and other facilities and higher fuel costs dampened earnings in recent years. Margins2005. A portion of the downtime in 20022005 was associated with hurricanes in the Gulf of Mexico. As a result of the storms, the company’s refinery in Pascagoula, Mississippi, was shut down for more than a month, and the company’s marketing and pipeline operations along the Gulf Coast were very depressed, and at one point hovered near their 12-year lows.
also disrupted for an extended period.
     Sales volumes forof refined products ofin 2005 were approximately 1.5 million barrels per day, or about 2 percent lower than in 2004. Branded gasoline sales volumes of approximately 600,000 barrels per day increased about 4 percent from the 2004 period. In 2004, refined-product sales volumes increased about 5 percent from 2003. The increase between periods was2003, primarily fromdue

to higher sales of gasoline, diesel fuel and fuel oil. Branded gasoline sales volumes of 567,000 barrels per day increased
2 percent from 2003. The sales improvement partially reflected the reintroduction of the Texaco brand in the Southeast. In 2003, sales volumes for refined products declined about 10 percent from the prior year. Industry demand in 2003 was weaker for branded gasoline, diesel and jet fuels and sales were lower under certain supply contracts.
Refer to the “Selected Operating Data” table, on page FS-10FS-12, for the three-year comparative refined-product sales volumes in the United States.
     In 2003, net specialspecial-item charges of $123 million included $160$132 million for environmental remediation and $28 million for employee severance costs associated with the global downstream restructuring and reorganization. These charges were partially offset by net gains onof $37 million from asset sales. In 2002, special charges of $215 million included amounts for environmental remediation, the write-down of the El Paso refinery in advance of sale and a litigation matter.




International Downstream –
Refining, Marketing and Transportation

              
Millions of dollars 2005   2004  2003 
    
Income1,2
 $1,786   $1,989  $685 
    
1 Includes Foreign Currency Effects:
  $(24)    $7   $(141) 
2 Includes Special-Item Charges:
             
Asset Dispositions $–   $–  $(24)
Asset Impairments/Write-offs  –    –   (123)
Restructuring and Reorganizations  –    –   (42)
    
Total $–   $–  $(189)
    
              
Millions of dollars 2004   2003  2002 
    
Segment Income1,2
 $1,989   $685  $31 
    
1Includes Foreign Currency Effects:
 $7   $(141) $(176)
2 Includes Special-Item Gains (Charges):
             
Asset Dispositions $–   $(24) $– 
Asset Impairments/Write-offs  –    (123)  (136)
Restructuring and Reorganizations  –    (42)  – 
    
Total $–   $(189) $(136)
    

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

     EarningsIncome of nearly $1.8 billion in 2005 decreased 10 percent from $2 billion in 2004 improved significantlybut was up about $1.1 billion from 2003. The decrease from the 2004 period was due mainly to lower sales volumes, higher costs for fuel and transportation, expenses associated with an explosion and fire at a 40 percent-owned, nonoperated terminal in the United Kingdom, and tax adjustments in various countries. These items more than offset an improvement in average refined-product



FS-9

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

margins between periods. The $1.3 billion increase in income from 2003 and 2002, mainly the result ofto 2004 reflected significantly higher average refined-product margins for refined products for both company and affiliate operationsin most of the company’s operating areas and higher earnings from international shipping operations. Margins in



FS-8

2004 were the highest in recent years. Earnings in 20042003 also included a benefit of $40 million related to changes in income tax laws.special-item charges (discussed below) and foreign currency losses that totaled more than $300 million.
     Total international refined products sales volumes were 2.3 million barrels per day in 2005, about 4 percent lower than 2004. The sales decline was primarily the result of lower gasoline trading activity and lower fuel-oil sales. Refined product sales volume of 2.4 million barrels per day in 2004 more thanwas about 4 percent higher than 2.3 million in 2003 and about 10 percent higher than 2.2 million in 2002. Weak economic conditions dampened industry demand in 2002.2003. Refer to the “Selected Operating Data” table, on page FS-10FS-12, for the three-year comparative refined-product sales volumes in the international areas.
     SpecialThe special-item charges of $189 million in 2003 included the write-down of the Batangas Refinery in the Philippines in advance of its conversion to a product terminal facility, employee severance costs associated with the global downstream restructuring and reorganization, the recognition of the impairment of certain assets in anticipation of their sale and the company’s share of losses from an asset sale and asset impairment by an equity affiliate. The special charge in 2002 was for a write-down of the company’s investment in its publicly traded Caltex Australia Limited affiliate to its estimated fair value.

Chemicals

              
Millions of dollars 2005   2004  2003 
    
Segment Income*
 $298   $314  $69 
    
*Includes Foreign Currency Effects: $–   $(3) $13 
              
Millions of dollars 2004   2003  2002 
    
Segment Income*
 $314   $69  $86 
    
*Includes Foreign Currency Effects: $(3)  $13  $3 

     The chemicals segment includes the company’s Oronite divisionsubsidiary and the company’s 50 percent share of its equity investment in Chevron Phillips Chemical Company LLC (CPChem). In 2004,2005, results for the company’s Oronite subsidiary improved onwere down due to significantly higher sales volumes.costs for feedstocks and adverse effects from the shut-down of operations in the U.S. Gulf Coast due to hurricanes. Earnings in 20042005 for CPChem increased aswere higher than 2004 on improved margins for commodity chemicals. Results for both businesses in 2005 were dampened by the resulteffects of increased chemical commodity margins and sales volumes and higher equity affiliate income. Protractedthe U.S. hurricanes. Significantly lower earnings in 2003 reflected weak demand for commodity chemicals and industry oversupply conditions suppressed earnings for this segment in 2003 and 2002.the period.



All Other

                      
Millions of dollars 2004 2003 2002  2005 2004 2003 
       
Charges Before Cumulative Effect of Changes in Accounting Principles $(20)  $(213) $(3,143) $(689)  $(20) $(213)
Cumulative Effect of Accounting Changes –   9 –  –   – 9 
       
Net Charges1,2
 $(20)  $(204) $(3,143) $(689)  $(20) $(204)
       
1 Includes Foreign Currency Effects
 $44   $43 $40 
1 Includes Foreign Currency Effects:
 $(51)   $44 $43 
2 Includes Special-Item Gains (Charges):
      
   
Dynegy-Related $–   $325 $(2,306) $–   $– $325 
Asset Impairments/Write-offs –    (84) –  –   –  (84)
Restructuring and Reorganizations –    (16) –  –   –  (16)
Tax Adjustments –   – 97 
Environmental Remediation Provisions –   –  (37)
Merger-Related Expenses –   –  (386)
       
Total $–   $225 $(2,632) $–   $– $225 
      

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

     The net charges of $689 million in 2005 increased significantly from $20 million in 2004. Approximately $400 million of the change related to larger benefits in 2004 from



FS-10

corporate-level tax adjustments. Higher charges in 2005 were associated with environmental remediation of properties that had been sold or idled and ongoing Unocal corporate-level activities. Interest expense also was higher in 2005 due to an increase in interest rates and the debt assumed with the Unocal acquisition.
     The improvement between 2003 and 2004 was primarily associated with the company’s investment in Dynegy, including gains from the redemption of certain Dynegy securities, higher interest income, lower interest expense and the favorable corporate-level tax adjustments. The net change between 2002 and 2003 was largely attributable to the differences in the effect of net special charges. The 2003 period also included lower interest expense and other corporate charges compared with 2002.
     Net specialspecial-item gains in 2003 included a Dynegy-related net benefit of $325 million, which was composed of a gain of $365 million from the exchange of the company’s investment in Dynegy preferred stock for cash and other Dynegy securities. This benefitsecurities that was partially offset by a $40 million charge for Chevron’s share of an asset impairment by Dynegy. Other special-item charges were for asset write-downs of $84 million, primarily in theChevron’s gasification business, which was later sold; $40 million for the company’s share of an asset impairment by Dynegy; and employee severance costs of $16 million.
     Special charges in 2002 included $2.3 billion related to Dynegy, composed of $1.6 billion for the write-down of the company’s investment in Dynegy common and preferred stock to its estimated fair value and $680 million for the company’s share of Dynegy’s own special items for asset write-downs and revaluations, and a loss on an asset sale. Refer also to page FS-11 for “Information Relating to the Company’s Investment in Dynegy.”

CONSOLIDATED STATEMENT OF INCOME

Comparative amounts for certain income statement categories are shown in the following table. For each category, the amountsbelow. Amounts associated with special items in the comparative periods are also indicated to assist in the explanation of the period-to-period changes. Besides the information in this section, separately disclosed on the face of the Consolidated Statement of Income are a gain from the exchange of Dynegy securities merger-related expenses, write-down of investments in Dynegy and the cumulative effect of changes in accounting principles. These matters are discussed elsewhere in MD&AManagement’s Discussion and Analysis and in Note 1427 to the Consolidated Financial Statements, on page FS-39.
              
Millions of dollars 2004   2003  2002 
    
Income (loss) from equity affiliates
 $2,582   $1,029  $(25)
    
Memo: Special gains (charges), before tax  –    179   (829)
    
Other income
 $1,853   $308  $222 
    
Memo: Special gains, before tax  1,281    217   – 
    
Operating expenses
 $9,832   $8,500  $7,795 
    
Memo: Special charges, before tax  85    329   259 
    
Selling, general and administrative expenses
 $4,557   $4,440  $4,155 
    
Memo: Special charges, before tax  –    146   180 
    
Depreciation, depletion and amortization
 $4,935   $5,326  $5,169 
    
Memo: Special charges, before tax  –    286   298 
    
Interest and debt expense
 $406   $474  $565 
    
Memo: Special charges, before tax  –    –   – 
    
Taxes other than on income
 $19,818   $17,901  $16,682 
    
Memo: Special charges, before tax  –    –   – 
    
Income tax expense
 $7,517   $5,294  $2,998 
    
Memo: Special charges (benefits)  291    (312)  (604)
    



FS-9

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

     Explanations follow for variations between years for the amounts in the table above – after consideration of the effects of special gains and charges – as well as for other income statement categories.FS-62. Refer to the preceding segment discussions in thisResults of Operations section, beginning of page FS-7, for additional information relating to specialspecial-item gains and charges.
              
Millions of dollars 2005   2004  2003 
    
Sales and other operating revenues
 $ 193,641   $ 150,865  $ 119,575 
    

Sales and other operating revenues were $151 billion in 2004, compared with $120 billion in 2003 and $98 billion in 2002. Revenues2005 increased inover 2004 and 2003 due primarily fromto higher prices for crude oil, natural gas and refined products worldwide. The amount in 2005 also included revenues for five months from former Unocal operations.

              
Millions of dollars 2005   2004  2003 
    
Income from equity affiliates
 $ 3,731   $ 2,582  $ 1,029 
    
Memo: Special-item gains, before tax $–   $–  $179 
Income (loss)

     Improved results for Tengizchevroil and Hamaca (Venezuela) accounted for nearly three-fourths of the increased income from equity affiliates in 2005. Profits in 2005 also increased at the company’s CPChem and Dynegy affiliates. The improvement in 2004 andfrom 2003 aswas the result of higher earnings improved for a number of affiliates, includingfrom the company’s downstream affiliates in the Asia-Pacific area, Tengizchevroil, CPChem, Dynegy and the Caspian Pipeline Consortium. Refer to Note 13, beginning on page FS-44, for a discussion of Chevron’s investment in affiliated companies.

              
Millions of dollars 2005   2004  2003 
    
Other income
 $ 828   $ 1,853  $ 308 
    
Memo: Special-item gains, before tax $–   $1,281  $217 

Other income in 20042005 included no special-item gains or losses; however, net special-item gains of $1.6 billion, primarily fromrelating to upstream property sales compared with gains of $286 millionwere nearly $1.3 billion in 2004 and $94more than $200 million in 2003. The increase from 2003 and 2002, respectively. Interestthrough 2005 was otherwise partly due to higher interest income increased to $199in each period – $400 million in 2005, $200 million in 2004 compared with aboutand $120 million in 2003 – on higher average interest rates and 2002, as a result of higher balances of cash and marketable securities. Foreign currency losses were $60 million $199 millionin both 2005 and $52004 and about $200 million in 2004, 2003 and 2002, respectively.2003.

              
Millions of dollars 2005   2004  2003 
    
Purchased crude oil and products
 $ 127,968   $ 94,419  $ 71,310 
    
Purchased crude oil and products were $94 billion in 2004, an increase of 32 percent from 2003, due mainly to higher prices and increased purchases of crude oil and products.

     Crude oil and product purchases in 2005 increased about 25approximately 35 percent in 2003, primarilyfrom 2004, due mainly to significantly higher prices for crude oil, natural gas and refined products as well as to the inclusion in 2005 of Unocal-related amounts for five months. Crude oil and product purchase costs increased 32 percent in 2004 from the prior year as a result of higher prices and increased purchased volumes of crude oil and products.

              
Millions of dollars 2005   2004  2003 
    
Operating, selling, general and administrative expenses
 $ 17,019   $ 14,389  $ 12,940 
    
Memo: Special-item charges, before tax $–   $85  $475 

Operating, selling, general and administrative expenses in 2005 increased 18 percent from a year earlier. Higher amounts in 2005 included former-Unocal expenses for five months, and for heritage-Chevron operations, higher costs for labor and transportation, uninsured costs associated with storms in the Gulf of $14 billionMexico, asset write-offs, repair and maintenance services, fuel costs for plant operations and a number of corporate items that individually were not significant. Total expenses increased from $13 billion in 2003. The increases in2003 to 2004 includeddue mainly to costs for chartering of crude oil tankers and other transportation expenses. During 2003, operating, selling, general and administrative

              
Millions of dollars 2005   2004  2003 
    
Exploration expense
 $ 743   $ 697  $ 570 
    

     Exploration expenses in 2005 increased nearly $1 billion, primarily from higher freight ratesmainly due to the inclusion of Unocal amounts for international shipping operations and higher costs associated with employee pension plans and other employee-benefit expenses.

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



FS-11

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

              
Millions of dollars 2005   2004  2003 
    
Depreciation, depletion and amortization
 $ 5,913   $ 4,935  $ 5,326 
    
Memo: Special-item charges, before tax $–   $–  $286 

Depreciation, depletion and amortization expenses in 2005 increased mainly as a result of five months of depreciation and depletion expense for the former Unocal assets and higher depreciation rates for certain heritage-Chevron crude oil and natural gas producing fields worldwide. Between 2003 and 2004, expenses did not change materially, between years after consideration of the effects of special-item charges.charges for asset impairments in 2003.

              
Millions of dollars 2005   2004  2003 
    
Interest and debt expense
 $ 482   $ 406  $ 474 
    

Interest and debt expense was $406 million in 2004, compared2005 increased mainly due to the inclusion of debt assumed with $474 million inthe Unocal acquisition and higher average interest rates for commercial paper borrowings. The decline between 2003 and $565 million in 2002. The lower amount in 2004 reflected lower average debt balances. The decline between 2003 and 2002 reflected lower average interest rates on commercial paper and other variable-rate debt and lower average debt levels.

              
Millions of dollars 2005   2004  2003 
    
Taxes other than on income
 $ 20,782   $ 19,818  $ 17,901 
    

Taxes other than on income were $19.8 billion, $17.9 billion in 2005 increased as a result of higher international taxes assessed on product values, higher duty rates in the areas of the company’s European downstream operations and $16.7 billionhigher U.S. federal excise taxes on jet fuel resulting from a change in 2004, 2003 and 2002, respectively.tax law that became effective in 2005. The increase in 2004 andfrom 2003 primarily reflected the weakening U.S. dollar on foreign currency-denominatedcurrency–denominated duties in the company’s European downstream operations.

              
Millions of dollars 2005   2004  2003 
    
Income tax expense
 $ 11,098   $ 7,517  $ 5,294 
    
Memo: Special-item charges (benefits) $    $ 291  $ (312) 
Income tax expense corresponded to effective

     Effective income tax rates ofwere 44 percent in 2005, 37 percent in 2004 and 43 percent in 2003, and 45 percent in 2002 after taking into accountexcluding the effect of net special items. Rates were higher in 2005 compared with the prior year due to the absence of benefits in 2004 from changes in the income tax laws for certain international operations and an increase in earnings in countries with higher tax rates. As compared with the effective tax rate in 2003, the effective tax rate in 2004 benefited from changes in the income tax laws for certain international operations, a change in the mix of international upstream earnings occurring in countries with different tax rates and favorable corporate consolidated tax effects. Refer also to the discussion of income taxes in Note 17 on page FS-4216 to the Consolidated Financial Statements.

Statements, beginning on page FS-47.

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

SELECTED OPERATING DATA1,21,2

             ��
  2004   2003  2002 
    
U.S. Upstream
             
Net Crude Oil and Natural Gas Liquids Production (MBPD)  505    562   602 
Net Natural Gas Production (MMCFPD)3
  1,873    2,228   2,405 
Net Oil-Equivalent Production (MBOEPD)  817    933   1,003 
Natural Gas Sales (MMCFPD)  4,518    4,304   5,891 
Natural Gas Liquids Sales (MBPD)  177    194   241 
Revenues From Net Production             
Liquids ($/Bbl) $34.12   $26.66  $21.34 
Natural Gas ($/MCF) $5.51   $5.01  $2.89 
    
International Upstream
             
Net Crude and Natural Gas Liquids Production (MBPD)  1,205    1,246   1,295 
Net Natural Gas Production (MMCFPD)3
  2,085    2,064   1,971 
Net Oil-Equivalent Production (MBOEPD)4
  1,692    1,704   1,720 
Natural Gas Sales (MMCFPD)  1,885    1,951   3,131 
Natural Gas Liquids Sales (MBPD)  105    107   131 
Revenues From Liftings             
Liquids ($/Bbl) $34.17   $26.79  $23.06 
Natural Gas ($/MCF) $2.68   $2.64  $2.14 
Net Oil-Equivalent Production Including Other Produced Volumes (MBPD)3,4
             
U.S.  817    933   1,003 
International  1,692    1,704   1,720 
      
Total  2,509    2,637   2,723 
    
U.S. Downstream – Refining, Marketing and Transportation
             
Gasoline Sales (MBPD)  701    669   680 
Other Refined Products Sales (MBPD)  805    767   920 
      
Total5
  1,506    1,436   1,600 
Refinery Input (MBPD)6
  914    951   979 
    
International Downstream – Refining Marketing and Transportation
             
Gasoline Sales (MBPD)  717    643   620 
Other Refined Products Sales (MBPD)  1,685    1,659   1,555 
      
Total7
�� 2,402    2,302   2,175 
Refinery Input (MBPD)  1,044    1,040   1,100 
    
1 Includes equity in affiliates.
             
2 MBPD = Thousands of barrels per day; MMCFPD = Millions of cubic feet per day; MBOEPD = Thousands of barrels of oil equivalents per day; Bbl = Barrel; MCF = Thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of gas = 1 barrel of oil.
 
3 Includes natural gas consumed on lease:
             
United States  50    65   64 
International  293    268   256 
4 Other produced volumes includes:
             
Athabasca Oil Sands – Net  27    15   – 
Boscan Operating Service Agreement  113    99   97 
      
   140    114   97 
5 Includes volume for buy/sell contracts:
  84    90   101 
6 The company sold its interest in the El Paso Refinery in August 2003.
             
7 Includes volume for buy/sell contracts:
  96    104   96 
              
  2005   2004  2003 
    
U.S. Upstream
             
Net Crude Oil and Natural Gas Liquids Production (MBPD)3
   455    505   562 
Net Natural Gas Production (MMCFPD)3,4
  1,634    1,873   2,228 
Net Oil-Equivalent Production (MBOEPD)3
  727    817   933 
Sales of Natural Gas (MMCFPD)  5,449    4,518   4,304 
Sales of Natural Gas Liquids (MBPD)  151    177   194 
Revenues From Net Production Liquids ($/Bbl) $ 46.97   $ 34.12  $ 26.66 
Natural Gas ($/MCF) $7.43   $5.51  $5.01 
International Upstream
             
Net Crude and Natural Gas Liquids Production (MBPD)3
  1,214    1,205   1,246 
Net Natural Gas Production (MMCFPD)3,4
  2,599    2,085   2,064 
Net Oil-Equivalent Production (MBOEPD)3,5
  1,790    1,692   1,704 
Sales Natural Gas (MMCFPD)  2,289    1,885   1,951 
Sales Natural Gas Liquids (MBPD)  108    105   107 
Revenues From Liftings Liquids ($/Bbl) $47.59   $34.17  $26.79 
Natural Gas ($/MCF) $3.19   $2.68  $2.64 
U.S. and International Upstream
             
Net Oil-Equivalent Production Including Other Produced Volumes (MBOEPD)4,5
             
United States  727    817   933 
International  1,790    1,692   1,704 
     
Total  2,517    2,509   2,637 
U.S. Downstream – Refining, Marketing and Transportation
             
Gasoline Sales (MBPD)6
  709    701   669 
Other Refined Products Sales (MBPD)  764    805   767 
     
Total (MBPD)7
  1,473    1,506   1,436 
Refinery Input (MBPD)8
  845    914   951 
International Downstream – Refining Marketing and Transportation
             
Gasoline Sales (MBPD)6
  669    717   643 
Other Refined Products Sales (MBPD)  1,626    1,685   1,659 
     
Total (MBPD)7,9
  2,295    2,402   2,302 
Refinery Input (MBPD)  1,038    1,044   1,040 
    
             
1 Includes equity in affiliates.
2 MBPD = Thousands of barrels per day; MMCFPD = Millions of cubic feet per day; MBOEPD = Thousands of barrels of oil equivalents per day; Bbl = Barrel; MCF = Thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of gas = 1 barrel of oil.
3 Includes net production from August 1, 2005, related to former Unocal properties.
4 Includes natural gas consumed on lease (MMCFPD):
United States  48   50   65 
International  332   293   268 
5 Includes other produced volumes (MBPD):
Athabasca Oil Sands – Net  32   27   15 
Boscan Operating Service Agreement  111   113   99 
   
   143   140   114 
6 Includes branded and unbranded gasoline
7 Includes volumes for buy/sell contracts (MBPD):
United States  82   84   90 
International  129   96   104 
8 The company sold its interest in the El Paso Refinery in August 2003.
 
9 Includes sales of affiliates (MBPD):
  540   536   525 



FS-10FS-12

INFORMATION RELATED TO INVESTMENT IN DYNEGY INC.

At year-end 2004, ChevronTexaco2005, Chevron owned an approximate 2524 percent equity interest in the common stock of Dynegy, – an energya provider engaged in power generation, gatheringof electricity to markets and processing of natural gas, andcustomers throughout the fractionation, storage, transportation and marketing of natural gas liquids.United States. The company also held an investment in Dynegy preferred stock.
     Investment in Dynegy Common Stock At December 31, 2004,2005, the carrying value of the company’s investment in Dynegy common stock was approximately $150$300 million. This amount was about $365$200 million below the company’s proportionate interest in Dynegy’s underlying net assets. This difference is primarily the result of write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value that were deemed to be other than temporary. The difference hashad been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors giving rise toassociated with the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly when appropriate to recognize a portion of the difference between these allocated values and Dynegy’s historical book values. The market value of the company’s investment in Dynegy’s common stock at December 31, 2004,the end of 2005 was approximately $450$470 million.
     Investments in Dynegy Notes and Preferred Stock At the beginningend of 2004,2005, the company held $223 million face value of Dynegy Junior Unsecured Subordinated Notes due 2016 and $400 million face value of Dynegy Series C Convertible Preferred Stock with a stated maturity of 2033.
     The Junior Notes were redeemed at face value during 2004, and gains of $54 million were recorded for the difference between the face amounts and the carrying values at the time of redemption. The face value of the company’s investment in the Series C preferred stock at December 31, 2004, was $400 million. The stock is recordedaccounted for at its fair value, which was estimated to be $370$360 million at December 31, 2004. Future temporaryyear-end 2005. Temporary changes in the estimated fair value of the preferred stock will beare reported in “Other comprehensive income.Comprehensive Income.” However, if in any future period a decline in fair value is deemed to be other than temporary, a charge against income in the period would be recorded. Dividends received from the preferred stock are recognizedrecorded to income in income each period.the period received.

LIQUIDITY AND CAPITAL RESOURCES

Cash, Cash Equivalentscash equivalents and Marketable Securitiesmarketable securitiesTotal balances were $10.7$11.1 billion and $5.3$10.7 billion at December 31, 20042005 and 2003,2004, respectively. Cash provided by operating activities in 20042005 was $14.7$20.1 billion, compared with $14.7 billion in 2004 and $12.3 billion in 2003 and $9.9 billion in 2002. These amounts were net of contributions to employee pension plans of $1.6 billion, $1.4 billion and $246 million in 2004, 2003 and 2002, respectively.2003.
     The 20042005 increase in cash provided by operating activities mainly reflected higher earnings in the worldwide upstream segment, including earnings from the former Unocal operations. Cash provided by operating activities was net of contributions to employee pension plans of $1.0 billion, $1.6 billion and downstream businesses.$1.4 billion in 2005, 2004 and 2003, respectively. Cash provided by investing activities included proceeds from asset sales of $2.7 billion in 2005, $3.7 billion in 2004 and $1.1 billion in 2003 and $2.3 billion in 2002.2003.
     Cash provided by operating activities and asset sales during 20042005 was sufficient to fund the company’s $8.7 billion capital and exploratory program, pay $3.2$3.8 billion of dividends to stockholders, reduce totalrepay approximately $970 million in long-term debt by $1.3 billion,and repurchase $2.1$3 billion of common stock, and increasestock. Partial consideration for the balanceacquisition of Unocal in August

2005 also included $7.5 billion in cash. Unocal balances of cash, cash equivalents and marketable securities by $5.5at the acquisition date totaled $1.6 billion.
     Dividends PaymentsThe company paid dividends of approximately $3.8 billion in 2005, $3.2 billion in 2004 and $3 billion in 2003 and 2002 were made for dividends.2003. In

September 2004, April 2005, the company increased its quarterly common stock dividend by 1012.5 percent to 4045 cents per share, on a post-stock split basis.share.
     Debt, Capital Leasecapital lease and Minority Interest Obligationsminority interest obligations Total debt and capital lease balances were $11.3$12.9 billion at December 31, 2004, down2005, up from $12.6$11.3 billion at year-end 2003.2004. The 2005 year-end balance included approximately $2.2 billion of debt and capital lease obligations assumed with the acquisition of Unocal. The company also had minority interest obligations of $172$200 million, downup from $268$172 million at December 31, 2003.2004.
     The company’s debt and capital lease obligations due within one year, consisting primarily of commercial paper and the current portion of long-term debt, totaled $5.6 billion at December 31, 2004, down2005, unchanged from $6.0 billion at December 31, 2003.2004. Of these amounts, $4.7$4.9 billion and $4.3$4.7 billion were reclassified to long-term at the end of each period, respectively. At year-end 2004,2005, settlement of these obligations was not expected to require the use of working capital in 2005,2006, 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.appropriate and economic.

     At year-end 2004, ChevronTexaco2005, the company had $4.7$4.9 billion in committed credit facilities with various major banks, which permitted the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowings and also can be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management



FS-13

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

believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at December 31, 2004.2005. In addition, the company hadhas three existing effective “shelf” registrationsregistration statements 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. Following the acquisition of Unocal, the company withdrew Unocal’s “shelf” registration statements.
     In 2004, repaymentsOctober 2005, the company fully redeemed the Unocal subsidiary Pure Resources’ 7.125 percent Senior Notes due 2011 for $395 million. The company’s $150 million of long-term debtTexaco Brasil zero coupon notes were paid at maturity included $500in November 2005. In December 2005, the company exercised a par-call redemption of $200 million of 6.625 percent ChevronTexaco Corporation bonds, an aggregate $265 million of various Philippine debt and $240 million of ChevronTexaco Corporation 8.11 percent notes.



FS-11

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

In the third quarter 2004, $300 million of 6 percentin Texaco Capital Inc., 5.7 percent Notes due June 2005, were also retired.2008.
     In February 2006, the company retired Union Oil bonds at maturity for approximately $185 million.
     Texaco Capital LLC, a wholly owned finance subsidiary, issued Deferred Preferred Shares Series C (Series C), in December 1995. In February 2005, the company redeemed the Series C shares and paid accumulated dividends at a cost of approximately $140 million.
     In January 2005, the company contributed $98 million to its Employee Stock Ownership Plan (ESOP) to permit the ESOP to make a $144 million debt service payment, which included a principal payment of $113 million.
     In the second quarter 2004, ChevronTexacoChevron entered into $1 billion of interest rate fixed-to-floating swap transactions.transactions, in which the company receives a fixed interest rate and pays a floating rate, based on the notional principal amounts. Under the terms of the swap agreements, of which $250 million and $750 million will terminate in September 2007 and February 2008, respectively, the net cash settlement will be based on the difference between fixed-rate and floating-ratefloating rate interest amounts.
     ChevronTexaco’sChevron’s senior debt is rated AA by Standard and Poor’s Corporation and Aa2 by Moody’s Investor Service, except forInvestors Service. The company’s senior debt of Texaco Capital Inc., which is rated Aa3. ChevronTexaco’sAa3, and Union Oil Company of California bonds are rated
A1 by Moody’s. These companies are wholly owned subsidiaries of Chevron. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and Prime 1P-1 by Moody’s, and the company’s Canadian commercial paper is rated R-1 (middle) by Dominion Bond Rating Service. All of these ratings denote high-quality investment-grade securities.
     The company’s future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. Further reductions from debt balances at December 31, 2004,2005, are dependent upon many factors, including management’s continuous assessment of debt as an appropriate component of the company’s overall capital structure. The company believes it has substantial borrowing capacity to meet unanticipated cash requirements, and during periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, the company believes that it has the flexibility to increase borrowings and/or modify capital-spending plans or both to continue paying the common stock dividend and maintain the company’s high-quality debt ratings.
     Tengizchevroil Funding As part of the funding of the expansion of Tengizchevroil’s (TCO) production facilities, in the fourth quarter 2004 ChevronTexaco purchased from TCO $2.2 billion of 6.124 percent Series B Notes (Series B), due 2014. Interest on the notes is payable semiannually, and principal is to be repaid semi-annually in equal installments beginning in February 2008.
     Immediately following the purchase of the Series B, ChevronTexaco received from TCO approximately $1.8 billion, representing a repayment of subordinated loans from the company, interest
and dividends. The $2.2 billion investment in the Series B Notes, which the company intends to hold until maturity, and the $1.8 billion distribution were recorded on the Consolidated Balance Sheet to “Investments and Advances.”
Common Stock Repurchase Program The company announcedIn connection with a stock$5 billion stock- repurchase program on March 31, 2004. Acquisitionsinitiated in April 2004, the company acquired 92.1 million of its common shares for $5 billion through November 2005. During 2005, about 49.8 million of common shares were repurchased under this program for a total cost of $2.9 billion.
     In December 2005, the company authorized the acquisition of up to an additional $5 billion may be madeof its common shares from time to time at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. The program is for a period of up to three years and may be discontinued at any time. TheUnder this program, the company purchased 42,324,000acquired approximately 1.7 million shares in the open market for $2.1 billion through$100 million during December 2004.2005. Purchases through February 2005mid-February 2006 increased the total shares acquired to 47,969,000 for $2.4 billion.8.3 million at a cost of $481 million.
     Capital and Exploratory Expendituresexploratory expenditures TotalExcluding the $17.3 billion acquisition of Unocal Corporation, total reported expenditures for 20042005 were $8.3$11.1 billion, including $1.56$1.7 billion for the company’s share of affiliates’ expenditures, which did not require cash outlays by the company. In 20032004


Capital and 2002,Exploratory Expenditures

                                       
  2005   2004   2003 
Millions of dollars U.S.  Int'l.  Total   U.S.  Int'l.  Total   U.S.  Int'l.  Total 
       
Upstream – Exploration and Production $2,450  $5,939  $8,389   $1,820  $4,501  $6,321   $1,641  $4,034  $5,675 
Downstream – Refining, Marketing and Transportation  818   1,332   2,150    497   832   1,329    403   697   1,100 
Chemicals  108   43   151    123   27   150    173   24   197 
All Other  329   44   373    512   3   515    371   20   391 
       
Total $3,705  $7,358  $11,063   $2,952  $5,363  $8,315   $2,588  $4,775  $7,363 
       
Total, Excluding Equity in Affiliates $3,522  $5,860  $9,382   $2,729  $4,024  $6,753   $2,306  $3,920  $6,226 
       

FS-14

and 2003, expenditures were $7.4$8.3 billion and $9.3$7.4 billion, respectively, including the company’s share of affiliates’ expenditures of $1.1$1.6 billion and $1.4$1.1 billion in the corresponding periods.
     Of the total 2004 reported$11.1 billion in expenditures $6.3for 2005, about three-fourths, or $8.4 billion, or 76 percent,related to upstream activities. Approximately the same

percentage was also expended for upstream activities, compared with 77 percentoperations in 20032004 and 68��percent in 2002.2003. International upstream accounted for 71about 70 percent of the worldwide upstream totalinvestment in 2004 and 2003 and 70 percent in 2002,each of the years, reflecting the company’s continuing focus on international exploration and production activities.opportunities that are available outside the United States.
     Expenditures in 2004 increased 13 percent compared with 2003, primarily driven by higher upstream expenditures. Downstream spending increased 21 percent from 2003. Expenditures were higher in 2002 than in 2003, due in part to large lease acquisitions in the North Sea and the Gulf of Mexico, spending for the Athabasca Oil Sands Project in western Canada, and additional common stock investments in Dynegy.
     Including its share of spending by affiliates,In 2006, the company estimates 2005 capital and exploratory expenditures at $10 billion, which is about 20will be 33 percent higher than 2004.at $14.8 billion, including spending by affiliates. About $7.4three-fourths, or $11.3 billion, or 74 percent of the total, is targetedagain for exploration and production activities, with $4.9$8 billion of that amount targeted for outside the United States. The upstream spendingSpending is primarily targeted for the most promising exploratory prospects in the deepwater Gulf of Mexico and Westwestern Africa and major development projects in Angola, Nigeria, Kazakhstan and the deepwater Gulf of Mexico. Included in the upstream expenditures is about $400 million$1 billion to develop the company’s international natural gas resource base.
     Worldwide downstream spending in 20052006 is estimated at $1.9$2.8 billion, with about $1.5$1.9 billion for refining and marketing


Capital and Exploratory Expenditures
                                       
  2004   2003   2002 
Millions of dollars U.S.  Int’l.  Total   U.S.  Int’l.  Total   U.S.  Int’l.  Total 
       
Exploration and Production $1,820  $4,501  $6,321   $1,641  $4,034  $5,675   $1,888  $4,395  $6,283 
Refining, Marketing and Transportation  497   832   1,329    403   697   1,100    750   882   1,632 
Chemicals  123   27   150    173   24   197    272   37   309 
All Other  512   3   515    371   20   391    855*  176*  1,031 
       
Total $2,952  $5,363  $8,315   $2,588  $4,775  $7,363   $3,765  $5,490  $9,255 
       
Total, Excluding Equity in Affiliates $2,729  $4,024  $6,753   $2,306  $3,920  $6,226   $3,312  $4,590  $7,902 
       
*2002 conformed to 2004 presentation.                                      

FS-12

and $400$900 million for supply and transportation projects, including pipelines to support expanded upstream production. Approximately two-thirds of the total projected spending is outside the United States.
     Investments in chemicals businesses in 20052006 are budgeted at $200$250 million. Estimates for energy technology, information technology and facilities, real estate activities, power-related businesses and power-relatedother businesses total approximately $500$460 million.
     Pension Obligations In 2004,2005, the company’s pension plan contributions totaled $1.6approximately $1 billion, (approximately $1.3 billionincluding nearly $200 million to the Unocal plans. Approximately $800 million of the total was contributed to U.S. plans).plans. In 2005,2006, the company expectsestimates contributions towill be approximately $400$500 million. Actual amounts are dependent upon investmentplan-investment results, changes in pension obligations, regulatory environments and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations. Refer also to the discussion of pension accounting in “Critical Accounting Estimates and Assumptions”Assumptions,” beginning on page FS-18.FS-22.

FINANCIAL RATIOS

Financial Ratios

              
  At December 31 
  2005   2004  2003 
    
Current Ratio  1.4    1.5   1.2 
Interest Coverage Ratio  47.5    47.6   24.3 
Total Debt/Total Debt-Plus-Equity  17.0%   19.9%  25.8%
    

FINANCIAL RATIOS

Current Ratio– current assets divided by current liabilities. The current ratio isin all periods was adversely affected by the fact that ChevronTexaco’sChevron’s inventories are valued on a Last-In, First-Out (LIFO)LIFO basis. At year-end 2004,2005, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $3.0$4.8 billion.
     Interest Coverage Ratio – income before income tax expense, plus interest and debt expense and amortization of capitalized interest, divided by before-tax interest costs. The company’s interest coverage ratio was essentially unchanged between 2004 and 2005. The interest coverage ratio was higher in 2004 compared with 2003, primarily due to higher before-tax income and lower average debt balances.

     Debt Ratio – total debt as a percentage of total debt plus equity. Although total debt was higher at the end of 2005 than a year earlier, the debt ratio declined as a result of higher stockholders’ equity balances for retained earnings and the capital stock that was issued in connection with the Unocal acquisition. The decreasedecline in the debt ratio between the comparable periods2003 and 2004 was primarily due to lower average debt levels and higher retained earnings.



FS-15

Financial Ratios
              
       At December 31 
  2004   2003  2002 
    
Current Ratio  1.5    1.2   0.9 
Interest Coverage Ratio  47.6    24.3   7.6 
Total Debt/Total Debt-Plus-Equity  19.9%   25.8%  34.0%
    
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Direct or Indirect Guarantees*

                     
Millions of dollars Commitment Expiration by Period 
          2006-      After 
  Total  2005  2008  2009  2009 
 
Guarantees of Non-consolidated Affiliates or Joint Venture Obligations $963  $515  $210  $135  $103 
Guarantees of Obligations of Third Parties  130   70   16   4   40 
Guarantees of Equilon Debt and Leases  215   18   61   18   118 
 
                     
Millions of dollars Commitment Expiration by Period 
          2007-      After 
  Total  2006  2009  2010  2010 
 
Guarantees of non-consolidated affiliates or joint venture obligations $985  $454  $426  $35  $70 
Guarantees of obligations of third parties  294   113   136   8   37 
Guarantees of Equilon debt and leases  193   24   55   19   95 
 
  
*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.FS-16 through FS-17.

     At December 31, 2004,2005, the company and its subsidiaries provided guarantees, either directly or indirectly, of $963$985 million in guarantees for notes and other contractual obligations of affiliated companies and $130$294 million for third parties as described by major category below. There are no material amounts being carried as liabilities for the company’s obligations under these guarantees.

     Of the $963$985 million in guarantees provided to affiliates, $774$806 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. Included in these amounts are Unocal-related guarantees of $230 million associated with a construction completion guarantee for the debt financing of Unocal’s equity interest in the Baku-Tbilisi-Ceyhan (BTC) crude oil pipeline project. Approximately 9095 percent of the amounts guaranteed will expire by 2009,between 2006 and 2010 with the remaining guarantees expiring by the end of 2015. Under the terms of the guarantees, the company would be required to fulfill the guarantee should an affiliate be in default of its loan terms, generally for the full amounts disclosed. There are no recourse provisions, and no assets are held as collateral for these guarantees. The $189 millionremaining balance of the $963$179 million represents obligations in connection with pricing of power purchasepower-purchase agreements for certain of itsthe company’s cogeneration affiliates. Under the terms of these guarantees, the company may be required to make payments under certain conditions if the affiliate doesaffiliates do not perform under the agreements. There are no recourse provisions to third parties, and no assets are held as collateral for these pricing guarantees.
     Guarantees of $130$294 million have been provided to third parties, including guarantees of approximately $40$150 million ofrelated to construction loans to host governments in the company’s international upstream operations. The remaining guarantees of $90$144 million were provided principally as conditionscon-

ditions 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 7085 percent of the total amounts guaranteed will expire in 2009,2010, with the remainder expiring after 2009.2010. The company would be required to perform under the terms of the guarantees should an entity be in default of its loan or contract terms, generally for the full amounts disclosed. Approximately $70$85 million of the guarantees have recourse provisions, which enable the company to recover any payments made under the terms of the guarantees from securities held over the guaranteed parties’ assets.
     At December 31, 2004, ChevronTexaco2005, Chevron also had outstanding guarantees for approximately $215about $190 million of Equilon debt and leases. Following the February 2002 disposition of its interest in Equilon, the company received an indemnification from Shell



FS-13

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

Oil Company (Shell) for any claims arising from the guarantees. The company has not recorded a liability for these guarantees. Approximately 4550 percent of the amounts guaranteed will expire within the 20052006 through 20092010 period, with the guarantees of the remaining amounts expiring by 2019.
     Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover certain contingent liabilities, including those associated with the Unocal patent litigation.liabilities. The company would be required to perform should the indemnified liabilities become actual losses. Should that occur, the company could be required to make future payments up to $300 million. Through the end of 2004,2005, the company paid approximately $28$38 million under these contingencies and had agreed to pay approximately $10 million additional under an award of arbitration, subject to minor adjustments yet to be resolved.indemnities. The company mayexpects to receive additional requests for indemnification payments in the future.
     The company has also provided indemnities relating to contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the periods of Texaco’s ownership interests in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims relating to Equilon indemnities must be asserted either as early as February 2007, or no later than February 2009, and claims relating to Motiva must be asserted no later than February 2012. Under the terms of the indemnities, there is no maximum limit on the amount of potential future payments. The company has not recorded any liabilities for possible claims under these indemnities. The company posts no assets as collateral and has made no payments under the indemnities.
     The amounts payable for the indemnities described above are to be net of amounts recovered from insurance carriers


FS-16

and others and net of liabilities recorded by Equilon or Motiva prior to September 30, 2001, for any applicable incident.
     In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets of Unocal’s 76 Products Company business that existed prior to its sale in 1997. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments by the company; however, the purchaser shares certain costs under this indemnity up to an aggregate cap of $200 million. Claims relating to these indemnities must be asserted by April 2022. Through the end of 2005, approximately $113 million had been applied to the cap, which includes payments made by either Unocal or Chevron totaling $80 million.
Securitization In other off-balance-sheet arrangements, theThe company securitizes certain retail and trade accounts receivable in its downstream business through the use of qualifying special purpose entities (SPEs). At December 31, 2004,2005, approximately $1.2 billion, representing about 107 percent of ChevronTexaco’sChevron’s total current accounts receivable balance, were securitized. ChevronTexaco’sChevron’s total estimated financial exposure under these securitizations at December 31, 2004,2005, was approximately $50$60 million. These arrangements have the effect of accelerating ChevronTexaco’sChevron’s collection of the securitized amounts. In the event of the SPEs experiencing major defaults in the collection of receivables, ChevronTexacoChevron believes that it would have no loss exposure connected with third-party investments in these securitizations.
     Long-Term Unconditional Purchase Obligations and Commitments, Throughput Agreements and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, throughput agreements, and take-or-pay agreements, some of which relate to suppliers’supplier’s financing arrangements.
The agreements typically provide goods and services, such as pipeline and storage capacity, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are 2005 – $1.6 billion; 2006 – $1.7$2.2 billion; 2007 – $1.62007– $1.9 billion; 2008 – $1.5$1.8 billion; 2009 – $1.5$1.8 billion; 2010 – $0.5 billion; 2011 and after – $2.3$3.8 billion. Total payments under the agreements were approximately $2.1 billion in 2005, $1.6 billion in 2004, and $1.4 billion in 2003 and $1.2 billion in 2002.2003. The most significant take-or-pay agreement calls for the company to purchase approximately 55,000 barrels per day of refined products from an equity affiliate refiner in Thailand. This purchase agreement is in conjunction with the financing of a refinery owned by the affiliate and expires in 2009. The future estimated commitments under this contract are: 2005 – $1.2 billion; 2006 – $1.2$1.3 billion; 2007 – $1.3 billion; 2008 – $1.3 billion; and 2009 – $1.3 billion. Additionally,In 2005, under the terms of an agreement entered in 2004, the company entered into a 20-year agreementexercised its option to acquire additional regasification capacity at the Sabine Pass LNG terminal.Liquefied Natural Gas Terminal. Payments of $1.2$2.5 billion over the 20-year period are expected to commence in 2010.2009.
     Minority Interests The company has commitments of approximately $172$200 million related to minority interests in subsidiary companies.
     The following table summarizes the company’s significant contractual obligations:

Contractual Obligations

                                        
Millions of dollars Payments Due by Period  Payments Due by Period 
 2006 - After  2007- After 
 Total 2005 2008 2009 2009  Total 2006 2009 2010 2010 
On-Balance-Sheet: 
Short-Term Debt $816 $816 $– $– $– 
Long-Term Debt1, 2
 10,217 – 8,123 455 1,639 
On Balance Sheet: 
Short-Term Debt1
 $739 $739 $– $– $– 
Long-Term Debt1,2
 11,807 – 8,775 176 2,856 
Noncancelable Capital Lease Obligations 239 – 110 29 100  324 – 154 36 134 
Interest Expense 4,830 465 1,120 270 2,975  5,600 500 1,100 300 3,700 
Off-Balance-Sheet:  
Noncancelable Operating Lease Obligations 2,232 390 857 236 749  2,917 507 1,194 284 932 
Unconditional Purchase Obligations 1,000 300 600 100 –  1,200 500 600 100 – 
Through-Put and Take-or-Pay Agreements 9,400 1,350 4,250 1,450 2,350 
Throughput and Take-or-Pay Agreements 10,800 1,700 4,900 400 3,800 
  
1
$4.74.9 billion of short-term debt that the company expects to refinance is included in long-term debt. The repayment schedule above reflects the projected repayment of the entire amountamounts in the 2006 through 20082007–2009 period.
  
2
Includes guarantees of $360$247 of LESOP (leveraged employee stock ownership Plan)plan) debt, $127$14 due in 20052006 and $233 due after 2006.

FINANCIAL AND DERIVATIVE INSTRUMENTS

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



FS-14

     ChevronTexacoChevron also uses financial derivative commodity instruments for trading purposes, and thepurposes. The results of this activity were not material to the company’s financial position, net income or cash flows in 2004.2005.
     The company’s positions are monitored and reportedmanaged on a daily basis by an internal risk control group to ensure compliance with the company’s risk management policy that has been approved by the Audit Committee of the company’s Board of Directors.
     The financial derivative instruments used in the company’s risk management and trading activities consist mainly of futures, options, and swap contracts traded on the New York Mercantile Exchange and the International Petroleum Exchange. In addition, crude oil, natural gas and refined product swap contracts and optionsoption contracts are entered into principally with major financial institutions and other oil and gas companies in the “over-the-counter” markets.
     Virtually all derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income. Fair values are derived principally from market quotes and other independent third-party quotes.
     Each hypothetical 10 percent increase in the price of natural gas and crude oil would increase the fair value of the natural gas purchase derivative contracts by approximately $40$33 million and reduce the fair value of the crude oil sale



FS-17

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

derivative contracts by about $15$11 million. The same hypothetical decreasesdecrease in the prices of these commodities would result in the same opposite effects on the fair values of the contracts.
     The hypothetical effect on these contracts was estimated by calculating the cash value of the contracts as the difference between the hypothetical and contract delivery prices multiplied by the contract amounts.
     Foreign Currency The company enters into forward exchange contracts, generally with terms of 180 days or less, to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments forecasted to occur within 180 days. The forward exchange contracts are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.
     The aggregate effect on foreign exchange contracts of a hypothetical 10 percent change toincrease in the value of the U.S. dollar at year-end exchange rates2005 would be a reduction in the fair value of the foreign exchange contracts of approximately $50$70 million. The effect would be the opposite for a hypothetical 10 percent decrease in the year-end value of the U.S. dollar.
     Interest Rates The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements are based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts. Interest rate swaps related to a portion of the company’s fixed-rate debt are accounted for as fair value hedges, whereas interest rate swaps relating to a portion of the company’s floating-rate debt are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.
     During 2004, four new swaps were initiated to hedge a portion of the company’s fixed-rate debt. At year-end 2004,2005, the weighted average maturity of “receive fixed” interest rate swaps was approximately three2 years. There were no “receive floating” swaps outstanding at year end.
A hypothetical increase of 10 basis points in market-fixedfixed interest rates would reduce the fair value of the “receive fixed” swaps by approximately $4$3 million.
     For the financial and derivative instruments discussed above, there was not a material change in market risk from that presented in 2003.between 2005 and 2004.
     The hypothetical variances used in this section were selected for illustrative purposes only and do not represent the company’s estimation of market changes. The actual impact of future market changes could differ materially due to factors discussed elsewhere in this report, including those set forth under the heading “Risk Factors” in partPart I, Item 11A of thisthe company’s 2005 Annual Report.Report on Form 10-K.

TRANSACTIONS WITH RELATED PARTIES

ChevronTexacoChevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply andor offtake agreements. Internationally, there are long-termLong-term purchase agreements are in place with the company’s refining affiliate in Thailand. Refer to page FS-14FS-17 for further discussion. Management believes the foregoing agreements and others have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.

LITIGATION AND OTHER CONTINGENCIES

MTBE The companyChevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive.
     The companyChevron is a party to more than 70 lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners, related to the use of MTBE in certain oxygenated gasolines and the alleged seepage of MTBE into groundwater. Resolution of these actions may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future.
     The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company does not use MTBE in the manufacture of gasoline in the United States and there are no detectable levels of MTBE in that gasoline.States.
     Environmental The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites including, but not limited to federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, and land development areas, whether operating, closed or sold.divested.
     The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for federal Superfund sites and analogous sites under state laws. In 2004,
              
Millions of dollars 2005   2004  2003 
    
Balance at January 1 $1,047   $1,149  $1,090 
Net Additions  731    155   296 
Expenditures  (309)   (257)  (237)
    
Balance at December 31
 $1,469   $1,047  $1,149 
    

     Included in the company recorded additional provisionsadditions for estimated remediation costs2005 were liabilities assumed in connection with the acquisition of Unocal. These liabilities relate primarily at refined productsto sites that had been divested or closed by Unocal prior to its acquisition by Chevron, includ-



FS-18

ing but were not limited to, former refineries, transportation and distribution facilities and service stations; former crude oil and natural gas fields and mining operations, as well as active mining operations. Other liability additions during 2005 for heritage-Chevron related primarily to refined-product marketing sites and various operating, closed or divested facilities in the United States.
              
Millions of dollars 2004   2003  2002 
    
Balance at January 1 $1,149   $1,090  $1,160 
Net Additions  155    296   229 
Expenditures  (257)   (237)  (299)
    
Balance at December 31
 $1,047   $1,149  $1,090 
    

     The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state or local regulations. No single remediation site at year-end 20042005 had a recorded liability that was material to the company’s financial position, results of operations or liquidity.



FS-15

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

     As of December 31, 2004, ChevronTexaco2005, Chevron was involved with the remediation activities of 210221 sites atfor which it had been identified as a potentially responsible party or otherwise by the U.S. Environmental Protection


Protection Agency (EPA) or other regulatory agencies under the provisions of the federal Superfund law or analogous state laws. The company’s remediation reserve for these sites at year-end 20042005 was $107$139 million. The federal Superfund law and analogous state laws provide for joint and several liability for all responsible parties. Any future actions by the EPA or other regulatory agencies to require ChevronTexacoChevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s consolidated financial position or liquidity.
     Of the remaining year-end 20042005 environmental reserves balance of $940$1,330 million, $712$855 million related to more than 2,000approximately 2,250 sites for the company’s U.S. downstream operations, including refineries and other plants, marketing locations

(i.e. (i.e., service stations and terminals), and pipelines. The remaining $228$475 million was associated with various sites in the international downstream ($111101 million), upstream ($69257 million), chemicals ($50 million) and chemicalsother ($4867 million). Liabilities at all sites, whether operating, closed or divested, were primarily associated with the company’s plans and activities to remediate soil and/or groundwater contamination or both. These and other activities include one or more of the following: site assessment; soil excavation; offsite disposal of contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid and vapor from soil; groundwater extraction and treatment; and monitoring of the natural attenuation of the contaminants.
     It is likely that the company will continue to incur additional liabilities, beyond those recorded, for environmental remediation relating to past operations. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. Although the amount of future costs may be material to the company’s results of operations in the period in which they are recognized, the company does not expect these costs will have a material adverse effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemical companies.
     Prior to January 1, 2003, additional reserves for dismantlement, abandonment and restoration of its worldwide oil and gas and coal properties at the end of their productive lives, which
included costs related to environmental issues, were recognized on a unit-of-production basis as accumulated depreciation, depletion and amortization. Effective January 1, 2003, the company implemented FASFinancial Accounting Standards Board Statement No. 143,“Accounting for Asset Retirement Obligations.”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 of $4.3 billion for asset retirement obligations at year-end 2004 was $2.9 billion. Refer also2005 related primarily to Note 25 on page FS-53 related to FAS 143.upstream and coal properties.
     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 preventsprevent estimation of the fair value of the asset retirement obligation.
     Refer also to Note 24, beginning on page FS-59, related to FAS 143 and the company’s adoption in 2005 of FIN 47, FASB Interpretation No. 47,“Accounting for Conditional Asset Retirement Obligations – An Interpretation of FASB Statement No. 143”(FIN 47), and the discussion of “Environmental Matters” on page FS-18 for additional information related to environmental matters.FS-21.
     Income Taxes The company estimatescalculates its income tax expense and liabilities quarterly. These liabilities generally are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been estimated.calculated. The U.S. federal income tax liabilities have been settled through 1996 for Chevron Corporation (formerly ChevronTexaco (formerly Chevron),Corporation) and 1997 for ChevronTexacoChevron Global Energy Inc. (formerly Caltex)Caltex Corporation), Unocal Corporation (Unocal), and 1991 for Texaco.Texaco Inc. (Texaco). The company’s California franchise tax liabilities have been settled through 1991 for Chevron, 1998 for Unocal 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


FS-19

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

taxes for all years under examination or subject to future examination.
     Global Operations ChevronTexacoChevron and its affiliates have operationsconduct business activities in approximately 180 countries. Areas in which the company and its affiliates have significant operations or ownership interests include the United States, Canada, Australia, the United Kingdom, Norway, Denmark, France, the Netherlands, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, Republic of the Congo, Angola, Nigeria, Chad, South Africa, the Democratic Republic of the Congo, Indonesia, Bangladesh, the Philippines, Myanmar, Singapore, China, Thailand, Vietnam, Cambodia, Azerbaijan, Kazakhstan, 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. Through an affiliate, the company participates in the development of the Baku-Tbilisi-Ceyhan (BTC) pipeline through Azerbaijan, Georgia and Turkey. Also through an affiliate, the company has an interest in the Chad/Cameroon pipeline. The company’s CPChemPetrolera Ameriven affiliate operates the Hamaca project in Venezuela. The company’s Chevron Phillips Chemical Company LLC (CPChem) affiliate manufactures and markets a wide range of petrochemicals on a worldwide basis, with manufacturing facilities in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar, Mexico and Belgium.
     The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates, including the United States. As has occurred in the past, actions could be taken by host governments to increase public ownership of the company’s partially or wholly owned businesses or assets or to impose additional taxes or royalties on the company’s operations or both.


FS-16

     In certain locations, host governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries. Internal unrest, acts of violence or strained relations between a host government and the company or other governments may affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results, and are carefully considered by management when evaluating the level of current and future activity in such countries. Refer to page FS-6 for a discussion of the company’s transition agreement with Petróleos de Venezuela, S.A. (PDVSA), the Venezuelan state-owned petroleum company, to convert contracts for the Boscan and LL-652 operating service agreements into an Empresa Mixta.
     Equity Redetermination For crude oil and natural gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude oil and natural gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermina-tion process has been under way since 1996 for ChevronTexaco’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills, California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. ChevronTexaco currently estimates its maximum possible net before-tax liability at approximately $200 million. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at about $50 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.
Suspended Wells The company suspends the costs of exploratory wells pending a final determination of the commercial potential of the related crude oil and natural gas
fields. The ultimate disposition of these well costs is dependent on the results of future drilling activity, or development decisions or both. If the company decides not to continue development, the costs of these wells are expensed. At December 31, 2004,2005, the company had $671 millionapproximately $1.1 billion of suspended exploratory wells included in properties, plant and equipment, an increase of $122more than $400 million from 20032004 and an increase of $193less than $600 million from 2002.2003. Of the increase in 2005, about $300 million was the year-end suspended well balance for the former-Unocal operations. The balance at year-end 20042005 balance primarily reflects drilling activities in the United States, Nigeria and Nigeria.
     The SEC has issued several comment letters to companies in the oil and gas industry related to the accounting for suspended exploratory wells, particularly for those suspended under certain circumstances for more than one year.
     The company’s accounting policy in this regard is to capitalize the cost of exploratory wells pending determination of whether the wells found proved reserves. Costs of wells that find proved reserves remain capitalized. Costs also are capitalized for wells that find commercially producible reserves that cannot be classified as proved, pending one or more of the following: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory wells that are under way or firmly planned, and (3) securing final regulatory approvals for development. Otherwise, well costs are expensed if a determination as to whether proved reserves were found cannot be made within one year following completion of drilling. All other exploratory well costs are expensed.
     This topic was discussed at the September 2004 meeting of the Emerging Issues Task Force (EITF) as Issue 04-9, “Accounting for Suspended Well Costs” (EITF 04-9). The discussion centered on whether certain circumstances would permit the continued capitalization of the costs for an exploratory well beyond one year in the absence of plans for another exploratory well. The outcome of the September 2004 EITF meeting was agreement
between the EITF and the FASB that the circumstances outlined were inconsistent with the provisions in FASB Statement No. 19,“Financial Accounting and Reporting by Oil and Gas Producing Companies”(FAS 19), and an amendment of FAS 19 would be required to formally adopt this view. In February 2005, the FASB issued a proposed FASB Staff Position (FSP) to amend FAS 19. Refer to Note 21 on page FS-45 to the Consolidated Financial Statements for a discussion of this FSP, the SEC’s comment letters and the company’s costs associated with suspended exploratory wells.Indonesia.
     The future trend of the company’s exploration expenses can be affected by amounts associated with well write-offs, including wells that had been previously suspended pending determination as to whether the well had found reserves that could be classified as proved. The effect on exploration expenses in future periods forof the $671 million$1.1 billion of suspended wells at year-end 20042005 is uncertain pending future activities, including normal project evaluation and additional drilling.
     Refer to Note 20, beginning on page FS-49, for additional discussion of suspended wells.
Equity Redetermination For crude oil and natural gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude oil and natural gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for Chevron’s interests in four producing zones at the referenced deliberationsNaval Petroleum Reserve at Elk Hills, California, for the time when the remaining interests in these zones were owned by the SEC and FASB, as isU.S. Department of Energy. A wide range remains for a possible net settlement amount for the effect onfour zones. Chevron currently estimates its maximum possible net before-tax liability at approximately $200 million. At the normal project-evaluation and future drilling activities for allsame time, a possible maximum net amount that could be owed to Chevron was estimated at about $50 million. The timing of the wells that have been suspended.settlement and the exact amount within this range of estimates are uncertain.
     Accounting for Buy/Sell Contracts In January and Februarythe first quarter 2005, the Securities and Exchange Commission (SEC) issued comment letters to ChevronTexacoChevron and other companies in the oil and gas industry requesting disclosure of information related to the accounting for buy/sell contracts. Under a buy/sell contract, a company agrees to buy a specific quantity and quality of a commodity to be delivered at a specific location while simultaneously agreeing to sell a specified quantity and quality of a commodity at a different location to the same counterparty. Physical delivery occurs for each side of the transaction, and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and risk of nonperformancenonperfor-


FS-20

mance by the counterparty. Both parties settle each side of the buy/sell through separate invoicing.
     The company routinely hasenters into buy/sell contracts, primarily in the United States downstream business, associated with crude oil and refined products. For crude oil, these contracts are used to facilitate the company’s crude oil marketing activity, which includes the purchase and sale of crude oil production, fulfillment of the company’s supply arrangements as to physical delivery location and crude oil specifications, and purchase of crude oil to supply the company’s refining system. For refined products, buy/sell arrangements are used to help fulfill the company’s supply agreements to customer locations and specifications.
     The company accountshas historically accounted for buy/sell transactions in the Consolidated Statement of Income the same as any otherfor a monetary transaction for which title passes,– purchases are reported as “Purchased crude oil and products;” sales are reported as “Sales and other operating revenues.” The SEC raised the risk and reward of ownership are assumed by the counterparties. At issue with the SEC isas to whether the industry’s accounting for buy/sell contracts instead should be shown net on the income statement and accounted for under the provisions of Accounting Principles Board (APB) Opinion No. 29,“Accounting for Nonmonetary Transactions”(APB 29). The company understands that others in the oil and gas industry may report buy/sell transactions on a net basis in the income statement rather than gross.
     The topic is under deliberation by the Emerging Issues Task Force (EITF) of the FASB deliberated this topic as Issue No. 04-13,“Accounting for Purchases and Sales of Inventory with the Same Counterparty.”Counterparty”The (EITF first discussed this issue in November 2004. Additional research is being performed04-13). At its September 2005 meeting, the EITF reached consensus that two or more legally separate exchange transactions with the same counterparty, including buy/sell transactions, should be combined and considered as a single arrangement for purposes of applying APB 29 when the transactions were entered into “in contemplation” of one another. EITF 04-13 was ratified by the FASB staff,in September 2005 and is effective for new arrangements, or modifications or renewals of existing arrangements, entered into beginning on or after April 1, 2006, which will be the effective date for the company’s adoption of this standard. Upon adoption, the company will report the net effect of buy/sell transactions on its Consolidated Statement of Income as “Purchased crude oil and products” instead of reporting the revenues associated with these arrangements as “Sales and other operating revenues” and the topic will be discussed again at a future EITF meeting.costs as “Purchased crude oil and products.”
     While this issue iswas under deliberation by the EITF, the SEC staff directed ChevronTexacoChevron and other companies in its January and February 2005 comment letters to disclose on the face of the income statement the amounts asso-


FS-17

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

ciatedassociated with buy/sell contracts and to discuss in a footnote to the financial statements the basis for the underlying accounting.
     With regard to the latter, the company’s accounting treatment The amounts for buy/sell contracts is based on the view that such transactions are monetary in nature. Monetary transactions are outside the scope of APB 29. The company believes its accounting is also supported by the indicators of gross reporting of purchases and sales in paragraph 3 of EITF Issue No. 99-19,“Reporting Revenue Gross as a Principal versus Net as an Agent.”Additionally, FASB Interpretation No. 39,“Offsetting of Amounts Related to Certain Contracts”(FIN 39), prohibits a receivable from being netted against a payable when the receivable is subject to credit risk unless a right of offset exists that is enforceable by law. The company also views netting the separate components of buy/sell contracts in the income statement to be inconsistent with the gross presentation that FIN 39 requires for the resulting receivable and payable on the balance sheet.
     The company’s buy/sell transactions are also similar to the “barrel back” example used in other accounting literature, including EITF Issue No. 03-11,“Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3”(which indicates a company’s decision to show buy/sell-types of transactions gross on the income statement as being a matter of judgment of the relevant facts and circumstances of the company’s activities) and Derivatives Implementation Group (DIG) Issue No. K1,“Miscellaneous: Determining Whether Separate Transactions Should be Viewed as a Unit".
     The company further notes that the accounting for buy/sell contracts as separate purchases and sales is in contrast to the accounting for other types of contracts typically described by the industry as exchange contracts, which are considered non-monetary in nature and appropriately shown net on the income statement. Under an exchange contract, for example, one company agrees to exchange refined products in one location for another company’s same quantity of refined products in another location. Upon transfer, the only amounts that may be invoiced are for transportation and quality differentials. Among other things, unlike buy/sell contracts, the obligations of each party to perform under the contract are not independent and the risks and rewards of ownership are not separately transferred.
     As shown on the company’s Consolidated Statement of Income “Sales and other operating revenues” for the three years ending December 31, 2004, included2005, were $23,822, $18,650 million,and $14,246, million and $7,963 million, respectively, for buy/sell contracts.respectively. These revenue amounts associated with buy/sell contracts represented 12 percent of total “Sales and other operating revenues” in 2005, 2004 and 2003 and 8 percent2003. Nearly all of these revenue amounts in 2002.each period associated with buy/sell contracts pertain to the company’s downstream segment. The costs associated with these
buy/sell revenue amounts are included in “Purchased crude oil and products” on the Consolidated Statement of Income in each period.
     Other Contingencies ChevronTexacoChevron receives claims from, and submits claims to, customers, trading partners, U.S. federal, state and local regulatory bodies, host governments, contractors, insurers and suppliers. The amounts of these claims, individually and in the aggregate, may be significant and may take lengthy periods to resolve.
     The company and its affiliates also continue to review and analyze their operations and may close, abandon, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in gains or losses in future periods.

ENVIRONMENTAL MATTERS

Virtually all aspects of the businesses in which the company engages are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. Most of the costs of complying with laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business.
     Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In addition to the costs for environmental protection associated with its ongoing operations and products, the company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste-disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-ChevronTexaconon-Chevron sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative or remedial work or both to meet current standards.
     Using definitions and guidelines established by the American Petroleum Institute, ChevronTexacoChevron estimated its worldwide environmental spending in 20042005 at approximately $1.1$1.3 billion for its consolidated companies. Included in these expenditures were $285$341 million of environmental capital expenditures and approximately $810$979 million of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the abandonment and restoration of sites.sites, which includes $14 million and $66 million, respectively, for Unocal activities for the last five months of 2005.
     For 2005,2006, total worldwide environmental capital expenditures are estimated at $710 million.$1.1 billion. 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



FS-21

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

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

CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS

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



FS-18

information over different reporting periods. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.
     The discussion in this section of “critical” accounting estimates or assumptions is according to the disclosure guidelines of the Securities and Exchange Commission (SEC), wherein:

1. the nature of the estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters, or the susceptibility of such matters to change;
 
2. the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.

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

     For example, the recording of deferred tax assets requires an assessment under the accounting rules that the future realization of the associated tax benefits be “more likely than not.” Another example is the estimation of oil and gas reserves under SEC rules that require “... geological”...geological and engineering data (that) demonstrate with reasonable certainty (reserves) to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.” Refer to Table V, “Reserve Quantity Information,” beginning on page FS-63FS-70, for the changes in these estimates for the three years ending December 31, 2004,2005, and to Table VII, “Changes

“Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves,”Reserves” on page FS-68FS-78 for estimates of proved-reserve values for each year-end 2002–2004,of the three years ending December 31, 2003 through 2005, which were based on year-end prices at the time. Note 1 to the Consolidated Financial Statements, beginning on page FS-34, 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”Affiliates,” on page FS-20FS-23, 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-30.FS-34. The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed by management with the audit committee of the Board of Directors.
     The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows:
     Pension and Other Postretirement Benefit Plans The determination of pension plan expense is based on a number of actuarial assumptions. Two critical assumptions are the expected long-

termlong-term rate of return on plan assets and the discount rate applied to pension plan obligations. For other postretirement employee benefit (OPEB) plans, which provide for certain health care and life insurance benefits for qualifying retired employees and which are not funded, critical assumptions in determining OPEB expense are the discount rate applied to benefit obligations and the assumed health care cost-trend rates used in the calculation of benefit obligations.
     Note 22 to the Consolidated Financial Statements,21, beginning on page FS-46,FS-50, includes information for the three years ending December 31, 2004,2005, on the components of pension and OPEB expense and on the underlying assumptions as well as on the funded status for the company’s pension plans at the end of 20042005 and 2003.2004.
     To estimate the long-term rate of return on pension assets, the company employs a rigorous process that incorporates actual historical asset-class returns and an assessment of expected future performance and takes into consideration external actuarial advice and asset-class factors. Asset allocations are regularlyperiodically 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


FS-22

studies. For example, theThe expected long-term rate of return on United States pension plan assets, which account for about 7072 percent of the company’s pension plan assets, has remained at 7.8 percent since 2002.
     The year-end market-related value of assets of the major U.S. pension plan assets used in the determination of pension expense was based on the market value in the preceding three months as opposed to the maximum allowable period of five years under U.S. accounting rules. Management considers the three-month period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, outside the United States, market value of assets as of the measurement date is used in calculating the pension expense.
     The discount rate assumptions used to determine U.S. and international pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality fixed-income debt instruments. At December 31, 2004,2005, the company calculatedselected a 5.5 percent discount rate based on Moody’s Aa Corporate Bond Index and a cash flow analysis using the Citigroup Pension Discount Curve for the major U.S. pension obligation using a 5.8 percent discount rate.and postretirement benefit plans. The discount rates used at the end of 2004 and 2003 and 2002 were 65.8 percent and 6.86 percent, respectively.
     An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa. Total pension expense for 20042005 was $564approximately $600 million. As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1 percent increase in the expected rate of return on assets of the company’s primary U.S. pension plan, which accounted for about 6053 percent of the company-widecompanywide pension obligation, would have reduced total pension plan expense for 20042005 by approximately $45$50 million. A 1 percent increase in the discount rate for this same plan would have reduced total benefit plan expense for 20042005 by approximately $115$130 million. The actual rates of return on plan assets and discount rates may vary significantly from estimates because of unanticipated changes in the world’s financial markets.
     In 2004,2005, the company’s pension plan contributions totaled $1.6were approximately $1 billion (approximately $1.3 billion(nearly $800 million to the U.S. plans). In 2005,2006, the company expects contributions to be approximately $400$500 million. Actual contribution amounts are dependent upon investmentplan-investment results, changes in pension obligations, regulatory environments and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations.


FS-19

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

     Pension expense is recorded on the Consolidated Statement of Income in “Operating expenses” or “Selling, general and administrative expenses” and applies to all business segments. Depending upon the funding status of the different plans, either a long-term prepaid asset or a long-term liability is recorded. Any unfunded accumulated benefit obligation in excess of recorded liabilities is recorded in “Other comprehensive income.” See Note 2221 to the Consolidated Financial Statements, beginning on page FS-46FS-50, for the pension-related balance sheet effects at the end of 20042005 and 2003.2004.
     For the company’s OPEB plans, expense for 20042005 was $197about $200 million and was also recorded as “Operating expenses” or “Selling, general and administrative expenses” in all business segments. At December 31, 2004, the discount rate applied to the company’s OPEB obligations was 5.8 percent – the same discount rate used for U.S. pension obligations.
     Effective January 1, 2005, the company amended its main U.S. postretirement medical plan to limit future increases in the company contribution. For current retirees, the increase in company contribution is capped at 4 percent each year. For future retirees, the 4 percent cap will be effective at retirement. Before retirement,For active employees and retirees below age 65 whose claims experiences are combined for rating purposes, the assumed health care cost trend rates start with 10.610 percent in 20042006 and gradually drop to 4.85 percent for 20102011 and beyond. Once the employee elects to retire, the trend rates are capped at 4 percent.
     As an indication of discount rate sensitivity to the determination of OPEB expense in 2004,2005, a 1 percent increase in the discount rate for the company’s primary U.S. OPEB plan, which accounted for about 9080 percent of the companywide OPEB obligation, would have decreased OPEB expense by approximately $20 million.
     Impairment of Property, Plant and Equipment and Investments in Affiliates The company assesses its property, plant and equipment (PP&E) for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in the company’s business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its fair value.
     Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for global or regional market supply and demand conditions for crude oil, natural gas, commodity chemicals and refined products. However, the impairment reviews and calculations are based on assumptions that are consistent with the company’s business plans and long-term investment decisions.
     The amount and income statement classification of major impairments of PP&E for the three years ending December 31, 2004,2005, are included in the commentary on the business segments elsewhere in this discussion, as well as in Note 2 to the Consolidated Financial Statements beginning on page FS-32.discussion. 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


FS-23

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

reviewed for impairment when the fair value of the investment falls below the company’s carrying value. When such a decline is deemed to be other than temporary, an impairment charge is recorded to the income statement for the difference between the investment’s carrying value and its estimated fair value at the time. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. Differing assumptions could affect whether an investment is impaired in any period andor the amount of the impairment and are not subject to sensitivity analysis.
     From time to time, the company performs impairment reviews and determines that no write-down in the carrying value of an asset or asset group is required. For example, when significant downward revisions to crude oil and natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the carrying value of the asset remains recoverable. Also, if the expectation of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed of. Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision was made to sell such assets, that is, the asset is held for sale, and the estimated proceeds less costs to sell were less than the associated carrying values.
     Business Combinations – Purchase-Price Allocation Accounting for business combinations requires the allocation of the company’s purchase price to the various assets and liabilities of the acquired business at their respective fair values. The company uses all available information to make these fair value determinations, and for major acquisitions, may hire an independent appraisal firm to assist in making fair-value estimates. In some instances, assumptions with respect to the timing and amount of future revenues and expenses associated with an asset might have to be used in determining its fair value. Actual timing and amount of net cash flows from revenues and expenses related to that asset over time may differ materially from those initial estimates, and if the timing is delayed significantly or if the net cash flows decline significantly, the asset could become impaired.
Goodwill When acquired as part of a business combination, goodwill is not subject to amortization. As required by Financial Accounting Standards Board (FASB) Statement No. 142,“Goodwill and Other Intangible Assets,”the company will test such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more
likely than not reduce the fair value of a reporting unit below its carrying amount. The goodwill arising from the Unocal acquisition is described in more detail in Note 2, beginning on page FS-36.
Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters and environmental remediation. Actual costs can frequently vary from estimates for a variety of reasons. For example, the costs from settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the amount of damages. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation; the determination of additional information on the extent and nature of site contamination; and improvements in technology.
     Under the accounting rules, a liability is recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally records these losses as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income. Refer to the business segment discussions elsewhere in this discussion and in Note 2 to the Consolidated Financial Statements on page FS-32 for the effect on earnings from losses associated with certain litigation and environmental remediation and tax matters for the three years ended December 31, 2004.2005.


FS-20

     An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss.
      American Jobs Creation Act of 2004 In October 2004, the American Jobs Creations Act of 2004 (the Act) was passed into law. The Act provides deduction from income for qualified domestic refining and upstream production activities, which will be phased in from 2005 through 2010. For that specific category of income, the company expects the net effect of this provision of the Act to result in a decrease in the federal effective tax rate for 2005 and 2006 to approximately 34 percent, based on current earnings levels. In the long term, the company expects that the new deduction will result in a decrease of the federal effective tax rate to about 32 percent for that category of income, based on current earnings levels.


FS-24

     Under the guidance in FASB Staff Position No. FAS 109-1,“Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,”the tax deduction on qualified production activities provided by the American Jobs Creation Act of 2004 will be treated as a “special deduction,” as described in FAS 109. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the period in which the deduction is claimed on the company’s tax return.
     The Act also provides for a limited opportunity to repatriate earnings from outside the United States at a special reduced tax rate that can be as low as 5.25 percent. In early 2005, the company was in the process of reviewing the guidance that the IRS issued on January 13, 2005, regarding this provision and also considering other relevant information. The company does not anticipate a major change in its plans for repatriating earnings from international operations under the provisions of the Act.

NEW ACCOUNTING STANDARDS

FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46) In January 2003, FIN 46 was issued, and established standards for determining under what circumstances a variable interest entity (VIE) should be consolidated by its primary beneficiary. FIN 46 also requires disclosures about VIEs that the company is not required to consolidate but in which it has a significant variable interest. In December 2003, the FASB issued FIN 46-R, which not only includes amendments to FIN 46, but also requires application of the interpretation to all affected entities no later than March 31, 2004, for calendar year-reporting companies. Prior to this requirement, companies were required to apply the interpretation to special-purpose entities by December 31, 2003. The full adoption of the interpretation as of March 31, 2004, including the requirement relating to special-purpose entities, did not have a material impact on the company’s results of operations, financial position or liquidity.
FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,”(FSP FAS 106-2) In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) became law. The Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care plans that provide a benefit that is at least actuarially equivalent to Medicare

Part D. In May 2004, the FASB issued FSP FAS 106-2. One U.S. subsidiary was deemed at least actuarially equivalent and eligible for the federal subsidy. The effect on the company’s postretirement benefit obligation and the associated annual expense wasde minimis.
FASB Statement No. 151, “Inventory Costs, an Amendment of ARB No. 43, Chapter 4” (FAS 151)(FAS 151)In November 2004, the FASB issued FAS 151, which isbecame effective for the company on January 1, 2006. The standard amends the guidance in Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing,”Pricing” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and spoilage. In addition, the standard requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The company is currently evaluating the impactadoption of this standard.
FASB Statement No. 123R, “Share-Based Payment”(FAS 123R) In December 2004, the FASB issued FAS 123R, which requires that compensation cost relating to share-based payments be recognized in the company’s financial statements. The company currently accounts for those payments under the recognition and measurement principles ofAccounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,”and related interpretations. The company is preparing to implement this standard effective July 1, 2005. Although the transition method to be used to adopt the standard haswill not been selected, the impact of adoption is expected to have a minimalan impact on the company’s results of operations, financial position andor liquidity. Refer to Note 1, beginning on page FS-30, for the company’s calculation of the pro forma impact on net income of FAS 123, which would be similar to that under FAS 123R.
     
FASB StatementEITF Issue No. 153, “Exchanges of Nonmonetary Assets — An Amendment of APB Opinion No. 29”04-6, “Accounting for Stripping Costs Incurred during Production in the Mining Industry” (FAS 153)(Issue 04-6) In December 2004,March 2005, the FASB issued FAS 153,ratified the earlier EITF consensus on Issue 04-6, which is effective for the company on January 1, 2006. Stripping costs are costs of removing overburden and other waste materials to access mineral deposits. The consensus calls for asset-exchange transactions beginning July 1, 2005. Under APB No. 29, assets received in certain types of nonmonetary exchanges were permittedstripping costs incurred once a mine goes into production to be recorded attreated as variable production costs that should be considered a component of mineral inventory cost subject to ARB No. 43, “Restatement and Revision of Accounting Research Bulletins.” Adoption of this accounting for its coal, oil sands and other mining operations will not have a significant effect on the carrying valuecompany’s results of the assets that were exchanged (i.e., recorded on a carryover basis). As amended by FAS 153, assets received in some circumstances will have to be recorded instead at their fair values. In the past, ChevronTexaco has not engaged in a large number of nonmonetary asset exchanges for significant amounts.operations, financial position or liquidity.



FS-21FS-25

  
Quarterly Results and Stock Market DataQUARTERLY RESULTS AND STOCK MARKET DATA
Unaudited
Unaudited
                                  
  2005 2004 
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 revenues1,2
 $52,457  $53,429  $47,265  $40,490   $41,612  $39,611  $36,579  $33,063 
Income (loss) from equity affiliates  1,110   871   861   889    785   613   740   444 
Other income  227   156   217   228    295   496   924   138 
    
TOTAL REVENUES AND OTHER INCOME
  53,794   54,456   48,343   41,607    42,692   40,720   38,243   33,645 
    
COSTS AND OTHER DEDUCTIONS
                                 
Purchased crude oil and products  34,246   36,101   31,130   26,491    26,290   25,650   22,452   20,027 
Operating expenses  3,819   3,190   2,713   2,469    2,874   2,557   2,234   2,167 
Selling, general and administrative expenses  1,340   1,337   1,152   999    1,319   1,231   986   1,021 
Exploration expenses  274   177   139   153    274   173   165   85 
Depreciation, depletion and amortization  1,725   1,534   1,320   1,334    1,283   1,219   1,243   1,190 
Taxes other than on income1
  5,063   5,282   5,311   5,126    5,216   4,948   4,889   4,765 
Interest and debt expense  135   136   104   107    112   107   94   93 
Minority interests  33   24   18   21    22   23   18   22 
    
TOTAL COSTS AND OTHER DEDUCTIONS
  46,635   47,781   41,887   36,700    37,390   35,908   32,081   29,370 
    
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
  7,159   6,675   6,456   4,907    5,302   4,812   6,162   4,275 
INCOME TAX EXPENSE
  3,015   3,081   2,772   2,230    1,862   1,875   2,056   1,724 
    
INCOME FROM CONTINUING OPERATIONS
  4,144   3,594   3,684   2,677    3,440   2,937   4,106   2,551 
INCOME FROM DISCONTINUED OPERATIONS
  –   –   –   –    –   264   19   11 
    
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
 $4,144  $3,594  $3,684  $2,677   $3,440  $3,201  $4,125  $2,562 
    
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, NET OF TAX
  –   –   –   –    –   –   –   – 
    
NET INCOME3
 $4,144  $3,594  $3,684  $2,677   $3,440  $3,201  $4,125  $2,562 
    
PER-SHARE OF COMMON STOCK4
                                 
INCOME FROM CONTINUING OPERATIONS
                                 
– BASIC
 $1.88  $1.65  $1.77  $1.28   $1.64  $1.38  $1.93  $1.21 
– DILUTED
 $1.86  $1.64  $1.76  $1.28   $1.63  $1.38  $1.93  $1.20 
    
INCOME FROM DISCONTINUED OPERATIONS
                                 
– BASIC
 $–  $–  $–  $–   $–  $0.13  $0.01  $– 
– DILUTED
 $–  $–  $–  $–   $–  $0.13  $0.01  $– 
    
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
                                 
– BASIC
 $–  $–  $–  $–   $–  $–  $–  $– 
– DILUTED
 $–  $–  $–  $–   $–  $–  $–  $– 
    
NET INCOME
                                 
– BASIC
 $1.88  $1.65  $1.77  $1.28   $1.64  $1.51  $1.94  $1.21 
– DILUTED
 $1.86  $1.64  $1.76  $1.28   $1.63  $1.51  $1.94  $1.20 
    
DIVIDENDS
 $0.45  $0.45  $0.45  $0.40   $0.40  $0.40  $0.37  $0.36 
COMMON STOCK PRICE RANGE
– HIGH
 $64.45  $65.77  $59.34  $62.08   $56.07  $54.49  $47.50  $45.71 
– LOW
 $55.75  $56.36  $50.51  $50.55   $50.99  $46.21  $43.95  $41.99 
    
1 Includes consumer excise taxes:
 $2,173  $2,268  $2,162  $2,116   $2,150  $2,040  $1,921  $1,857 
2 Includes amounts for buy/sell contracts:
 $5,897  $6,588  $5,962  $5,375   $5,117  $4,640  $4,637  $4,256 
3 Net benefits (charges) for special items included in “Net Income”:
 $–  $–  $–  $–   $146  $486  $585  $(55)
4 The amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
 
                                  
  2004               20031
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 revenues2,3
 $41,612  $39,611  $36,579  $33,063   $30,018  $30,058  $28,982  $30,517 
Income from equity affiliates  785   613   740   444    262   287   216   264 
Other income  295   496   924   138    67   147   52   42 
Gain from exchange of Dynegy securities  –   –   –   –    –   365   –   – 
    
TOTAL REVENUES AND OTHER INCOME
  42,692   40,720   38,243   33,645    30,347   30,857   29,250   30,823 
    
COSTS AND OTHER DEDUCTIONS
                                 
Purchased crude oil and products  26,290   25,650   22,452   20,027    17,907   18,024   17,187   18,192 
Operating expenses  2,874   2,557   2,234   2,167    2,488   2,227   1,853   1,932 
Selling, general and administrative expenses  1,319   1,231   986   1,021    1,172   1,198   1,061   1,009 
Exploration expenses  274   173   165   85    138   130   147   155 
Depreciation, depletion and amortization  1,283   1,219   1,243   1,190    1,309   1,394   1,400   1,223 
Taxes other than on income2
  5,216   4,948   4,889   4,765    4,643   4,417   4,511   4,330 
Interest and debt expense  112   107   94   93    111   115   118   130 
Minority interests  22   23   18   22    14   24   20   22 
    
TOTAL COSTS AND OTHER DEDUCTIONS
  37,390   35,908   32,081   29,370    27,782   27,529   26,297   26,993 
    
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
  5,302   4,812   6,162   4,275    2,565   3,328   2,953   3,830 
INCOME TAX EXPENSE
  1,862   1,875   2,056   1,724    837   1,363   1,363   1,731 
    
INCOME FROM CONTINUING OPERATIONS
  3,440   2,937   4,106   2,551    1,728   1,965   1,590   2,099 
INCOME FROM DISCONTINUED OPERATIONS
  –   264   19   11    7   10   10   17 
    
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
 $3,440  $3,201  $4,125  $2,562   $1,735  $1,975  $1,600  $2,116 
    
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, NET OF TAX
  –   –   –   –    –   –   –   (196)
    
NET INCOME4
 $3,440  $3,201  $4,125  $2,562   $1,735  $1,975  $1,600  $1,920 
    
PER-SHARE OF COMMON STOCK5
                                 
INCOME FROM CONTINUING OPERATIONS
                                 
– BASIC
 $1.64  $1.38  $1.93  $1.21   $0.82  $1.006 $0.75  $0.98 
– DILUTED
 $1.63  $1.38  $1.93  $1.20   $0.82  $1.006 $0.75  $0.98 
    
INCOME FROM DISCONTINUED OPERATIONS
                                 
– BASIC
 $–  $0.13  $0.01  $–   $–   0.01  $–  $0.01 
– DILUTED
 $–  $0.13  $0.01  $–   $–   0.01  $–  $0.01 
    
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
                                 
– BASIC
 $–  $–  $–  $–   $–   –  $–  $(0.09)
– DILUTED
 $–  $–  $–  $–   $–   –  $–  $(0.09)
    
NET INCOME
                                 
– BASIC
 $1.64  $1.51  $1.94  $1.21   $0.82  $1.016 $0.75  $0.90 
– DILUTED
 $1.63  $1.51  $1.94  $1.20   $0.82  $1.016 $0.75  $0.90 
    
DIVIDENDS
 $0.40  $0.40  $0.37  $0.36   $0.37  $0.36  $0.35  $0.35 
COMMON STOCK PRICE RANGE – HIGH
 $56.07  $54.49  $47.50  $45.71   $43.49  $37.28  $38.11  $35.20 
– LOW
 $50.99  $46.21  $43.95  $41.99   $35.57  $35.02  $31.06  $30.65 
    
1 2003 conformed to the 2004 presentation for discontinued operations.
                                 
2 Includes consumer excise taxes:
 $2,150  $2,040  $1,921  $1,857   $1,825  $1,814  $1,765  $1,691 
3 Includes amounts for buy/sell contracts:
 $5,117  $4,640  $4,637  $4,256   $3,538  $3,734  $3,751  $3,223 
4 Net benefits (charges) for special items included in “Net Income”:
 $146  $486  $585  $(55)  $89  $14  $(117) $(39)
5 The amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
6 Includes a benefit of $0.08 for the company’s share of a capital stock transaction of its Dynegy Inc. affiliate, which, under the applicable accounting rules, was recorded directly to retained earnings and not included in the net income for the period.


The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX) and on the Pacific Exchange. As of February 25, 2005,23, 2006, stockholders of record numbered approximately 227,000.230,000. There are no restrictions on the company’s ability to pay dividends.

FS-22FS-26

MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS

MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS
To the Stockholders of ChevronTexacoChevron Corporation
Management of ChevronTexacoChevron is responsible for preparing the accompanying Consolidated Financial Statements and the related information appearing in this report. The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgment.
     TheAs stated in its report included herein, the independent registered public accounting firm of PricewaterhouseCoopers LLP has audited the company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States), as stated in their report included herein..
     The Board of Directors of ChevronTexacoChevron has an Audit Committee composed of directors who are not officers or employees of the company. The Audit Committee meets regularly with members of management, the internal auditors and the independent registered public accounting firm to review accounting, internal control, auditing and financial reporting matters. Both the internal auditors and the independent registered public accounting firm have free and direct access to the Audit Committee without the presence of management.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a–15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on theInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the company’s management concluded that its internal control over financial reporting was effective as of December 31, 2004.2005.
     The company management’s assessment of the effectiveness of its internal control over financial reporting as of December 31, 2004,2005, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in theirits report which is included herein.

/S/ DAVID J. O’REILLY

DAVID J. O’REILLY

Chairman of the Board
and Chief Executive Officer

February 27, 2006

/S/ STEPHEN J. CROWE

STEPHEN J. CROWE

Vice President
and Chief Financial Officer

/S/ MARK A. HUMPHREY

MARK A. HUMPHREY

Vice President
and Comptroller



FS-27

     
/s/ DAVID J. O’REILLY/s/ STEPHEN J. CROWE/s/ MARK A. HUMPHREY
  
DAVID J. O’REILLYSTEPHEN J. CROWEMARK A. HUMPHREY
Chairman of the BoardVice PresidentVice President
and Chief Executive Officerand Chief Financial Officerand Comptroller
March 2, 2005
 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM  

FS-23

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors of ChevronTexacoChevron Corporation:
We have completed an integrated auditaudits of ChevronTexacoChevron Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 20042005, and auditsan audit of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE

In our opinion, the accompanying consolidated balance sheets andfinancial statements listed in the related consolidated statementsindex appearing under Item 15(a)(1) of income, comprehensive income, stockholders’ equity and cash flowsthe Annual Report on Form 10-K present fairly, in all material respects, the financial position of ChevronTexacoChevron Corporation and its subsidiaries at December 31, 20042005 and 2003,2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20042005, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
     As discussed in Note 24 beginning on page FS-59 to the Consolidated Financial Statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 20042005, based on criteria established inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004,2005, based on criteria established inInternal Control – Integrated Frameworkissued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
     A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.


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



/s/ PricewaterhouseCoopers LLP

San Francisco, California
March 2, 2005February 27, 2006

FS-24FS-28

  
Consolidated StatementCONSOLIDATED STATEMENT OF INCOME
Millions of Incomedollars, except per-share amounts
Millions of dollars, except per-share amounts
              
  Year ended December 31 
  2004   2003  2002 
    
REVENUES AND OTHER INCOME
             
Sales and other operating revenues1,2
 $150,865   $119,575  $98,340 
Income (loss) from equity affiliates  2,582    1,029   (25)
Other income  1,853    308   222 
Gain from exchange of Dynegy preferred stock  –    365   – 
    
TOTAL REVENUES AND OTHER INCOME
  155,300    121,277   98,537 
    
COSTS AND OTHER DEDUCTIONS
             
Purchased crude oil and products2
  94,419    71,310   57,051 
Operating expenses  9,832    8,500   7,795 
Selling, general and administrative expenses  4,557    4,440   4,155 
Exploration expenses  697    570   591 
Depreciation, depletion and amortization  4,935    5,326   5,169 
Taxes other than on income1
  19,818    17,901   16,682 
Interest and debt expense  406    474   565 
Minority interests  85    80   57 
Write-down of investments in Dynegy Inc.  –    –   1,796 
Merger-related expenses  –    –   576 
    
TOTAL COSTS AND OTHER DEDUCTIONS
  134,749    108,601   94,437 
    
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
  20,551    12,676   4,100 
INCOME TAX EXPENSE
  7,517    5,294   2,998 
    
INCOME FROM CONTINUING OPERATIONS
  13,034    7,382   1,102 
INCOME FROM DISCONTINUED OPERATIONS
  294    44   30 
    
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
 $13,328   $7,426  $1,132 
Cumulative effect of changes in accounting principles  –    (196)  – 
    
NET INCOME
 $13,328   $7,230  $1,132 
    
PER-SHARE OF COMMON STOCK3
             
INCOME FROM CONTINUING OPERATIONS
             
– BASIC
 $6.16   $3.55  $0.52 
– DILUTED
 $6.14   $3.55  $0.52 
INCOME FROM DISCONTINUED OPERATIONS
             
– BASIC
 $0.14   $0.02  $0.01 
– DILUTED
 $0.14   $0.02  $0.01 
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
             
– BASIC
 $–   $(0.09) $– 
– DILUTED
 $–   $(0.09) $– 
NET INCOME
             
– BASIC
 $6.30   $3.48  $0.53 
– DILUTED
 $6.28   $3.48  $0.53 
    
1 Includes consumer excise taxes:
 $7,968   $7,095  $7,006 
2 Includes amounts in revenues for buy/sell contracts (associated costs are in “Purchased crude oil and products”) See Note 16 on page FS-41:
 $18,650   $14,246  $7,963 
3 All periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
             
See accompanying Notes to the Consolidated Financial Statements.

FS-25

  
Consolidated Statement of Comprehensive Income
Millions of dollars
              
  Year ended December 31 
  2005   2004  2003 
    
REVENUES AND OTHER INCOME
             
Sales and other operating revenues1,2
 $193,641   $150,865  $119,575 
Income from equity affiliates  3,731    2,582   1,029 
Other income  828    1,853   308 
Gain from exchange of Dynegy preferred stock  –    –   365 
    
TOTAL REVENUES AND OTHER INCOME
  198,200    155,300   121,277 
    
COSTS AND OTHER DEDUCTIONS
             
Purchased crude oil and products2
  127,968    94,419   71,310 
Operating expenses  12,191    9,832   8,500 
Selling, general and administrative expenses  4,828    4,557   4,440 
Exploration expenses  743    697   570 
Depreciation, depletion and amortization  5,913    4,935   5,326 
Taxes other than on income1
  20,782    19,818   17,901 
Interest and debt expense  482    406   474 
Minority interests  96    85   80 
    
TOTAL COSTS AND OTHER DEDUCTIONS
  173,003    134,749   108,601 
    
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
  25,197    20,551   12,676 
INCOME TAX EXPENSE
  11,098    7,517   5,294 
    
INCOME FROM CONTINUING OPERATIONS
  14,099    13,034   7,382 
INCOME FROM DISCONTINUED OPERATIONS
  –    294   44 
    
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
 $14,099   $13,328  $7,426 
Cumulative effect of changes in accounting principles  –    –   (196)
    
NET INCOME
 $14,099   $13,328  $7,230 
    
PER-SHARE OF COMMON STOCK3
             
INCOME FROM CONTINUING OPERATIONS
             
– BASIC
 $6.58   $6.16  $3.55 
– DILUTED
 $6.54   $6.14  $3.55 
INCOME FROM DISCONTINUED OPERATIONS
             
– BASIC
 $–   $0.14  $0.02 
– DILUTED
 $–   $0.14  $0.02 
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
             
– BASIC
 $–   $–  $(0.09)
– DILUTED
 $–   $–  $(0.09)
NET INCOME
             
– BASIC
 $6.58   $6.30  $3.48 
– DILUTED
 $6.54   $6.28  $3.48 
    
              
  Year ended December 31 
  2004   2003  2002 
    
NET INCOME
 $13,328   $7,230  $1,132 
    
Currency translation adjustment             
Unrealized net change arising during period  36    32   15 
    
Unrealized holding (loss) gain on securities             
Net gain (loss) arising during period             
Before income taxes  35    445   (149)
Income taxes  –    –   52 
Reclassification to net income of net realized (gain) loss             
Before income taxes  (44)   (365)  217 
Income taxes  –    –   (76)
    
Total  (9)   80   44 
    
Net derivatives (loss) gain on hedge transactions             
Before income taxes  (8)   115   52 
Income taxes  (1)   (40)  (18)
    
Total  (9)   75   34 
    
Minimum pension liability adjustment             
Before income taxes  719    12   (1,208)
Income taxes  (247)   (10)  423 
    
Total  472    2   (785)
    
OTHER COMPREHENSIVE GAIN (LOSS), NET OF TAX
  490    189   (692)
    
COMPREHENSIVE INCOME
 $13,818   $7,419  $440 
    
              
1Includes consumer excise taxes:
 $8,719   $7,968  $7,095 
2Includes amounts in revenues for buy/sell contracts associated costs are in “Purchased crude oil and products.”
See Note 15, on page FS-46:
 $23,822   $18,650  $14,246 
3All periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
             
 
See accompanying Notes to the Consolidated Financial Statements.

FS-26FS-29

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Millions of dollars
              
  Year ended December 31 
  2005   2004  2003 
    
NET INCOME
 $14,099   $13,328  $7,230 
    
Currency translation adjustment             
Unrealized net change arising during period  (5)   36   32 
    
Unrealized holding (loss) gain on securities             
Net (loss) gain arising during period  (32)   35   445 
Reclassification to net income of net realized (gain)  –    (44)  (365)
    
Total  (32)   (9)  80 
    
Net derivatives (loss) gain on hedge transactions             
Net (loss) gain arising during period             
Before income taxes  (242)   (8)  115 
Income taxes  89    (1)  (40)
Reclassification to net income of net realized loss             
Before income taxes  34    –   – 
Income taxes  (12)   –   – 
    
Total  (131)   (9)  75 
    
Minimum pension liability adjustment             
Before income taxes  89    719   12 
Income taxes  (31)   (247)  (10)
    
Total  58    472   2 
    
OTHER COMPREHENSIVE (LOSS) GAIN, NET OF TAX
  (110)   490   189 
    
COMPREHENSIVE INCOME
 $13,989   $13,818  $7,419 
    
See accompanying Notes to the Consolidated Financial Statements.

FS-30

CONSOLIDATED BALANCE SHEET
Millions of dollars, except per-share amounts
          
  At December 31 
  2005   2004 
    
ASSETS
         
Cash and cash equivalents $10,043   $9,291 
Marketable securities  1,101    1,451 
Accounts and notes receivable (less allowance: 2005 – $156; 2004 – $174)  17,184    12,429 
Inventories:         
Crude oil and petroleum products  3,182    2,324 
Chemicals  245    173 
Materials, supplies and other  694    486 
      
Total inventories  4,121    2,983 
Prepaid expenses and other current assets  1,887    2,349 
    
TOTAL CURRENT ASSETS
  34,336    28,503 
Long-term receivables, net  1,686    1,419 
Investments and advances  17,057    14,389 
Properties, plant and equipment, at cost  127,446    103,954 
Less: Accumulated depreciation, depletion and amortization  63,756    59,496 
      
Properties, plant and equipment, net  63,690    44,458 
Deferred charges and other assets  4,428    4,277 
Goodwill  4,636    – 
Assets held for sale  –    162 
    
TOTAL ASSETS
 $125,833   $93,208 
    
LIABILITIES AND STOCKHOLDERS’ EQUITY
         
Short-term debt $739   $816 
Accounts payable  16,074    10,747 
Accrued liabilities  3,690    3,410 
Federal and other taxes on income  3,127    2,502 
Other taxes payable  1,381    1,320 
    
TOTAL CURRENT LIABILITIES
  25,011    18,795 
Long-term debt  11,807    10,217 
Capital lease obligations  324    239 
Deferred credits and other noncurrent obligations  10,507    7,942 
Noncurrent deferred income taxes  11,262    7,268 
Reserves for employee benefit plans  4,046    3,345 
Minority interests  200    172 
    
TOTAL LIABILITIES
  63,157    47,978 
    
Preferred stock (authorized 100,000,000 shares, $1.00 par value; none issued)  –    – 
Common stock (authorized 4,000,000,000 shares, $0.75 par value; 2,442,676,580 and 2,274,032,014 shares issued at December 31, 2005 and 2004, respectively)  1,832    1,706 
Capital in excess of par value  13,894    4,160 
Retained earnings  55,738    45,414 
Notes receivable – key employees  (3)   – 
Accumulated other comprehensive loss  (429)   (319)
Deferred compensation and benefit plan trust  (486)   (607)
Treasury stock, at cost (2005 – 209,989,910 shares; 2004 – 166,911,890 shares)  (7,870)   (5,124)
    
TOTAL STOCKHOLDERS’ EQUITY
  62,676    45,230 
    
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
 $125,833   $93,208 
    
See accompanying Notes to the Consolidated Financial Statements.

FS-31

CONSOLIDATED STATEMENT OF CASH FLOWS
Millions of dollars
              
  Year ended December 31 
  2005   2004  2003 
    
OPERATING ACTIVITIES
             
Net income $14,099   $13,328  $7,230 
Adjustments     
Depreciation, depletion and amortization  5,913    4,935   5,326 
Dry hole expense  226    286   256 
Distributions less than income from equity affiliates  (1,304)   (1,422)  (383)
Net before-tax gains on asset retirements and sales  (134)   (1,882)  (194)
Net foreign currency effects  62    60   199 
Deferred income tax provision  1,393    (224)  164 
Net (increase) decrease in operating working capital  (54)   430   162 
Minority interest in net income  96    85   80 
(Increase) decrease in long-term receivables  (191)   (60)  12 
Decrease (increase) in other deferred charges  668    (69)  1,646 
Cumulative effect of changes in accounting principles  –    –   196 
Gain from exchange of Dynegy preferred stock  –    –   (365)
Cash contributions to employee pension plans  (1,022)   (1,643)  (1,417)
Other  353    866   (597)
    
NET CASH PROVIDED BY OPERATING ACTIVITIES
  20,105    14,690   12,315 
    
INVESTING ACTIVITIES
             
Cash portion of Unocal acquisition, net of Unocal cash received  (5,934)   –   – 
Capital expenditures  (8,701)   (6,310)  (5,625)
Advances to equity affiliate  –    (2,200)  – 
Repayment of loans by equity affiliates  57    1,790   293 
Proceeds from asset sales  2,681    3,671   1,107 
Net sales (purchases) of marketable securities  336    (450)  153 
    
NET CASH USED FOR INVESTING ACTIVITIES
  (11,561)   (3,499)  (4,072)
    
FINANCING ACTIVITIES
             
Net (payments) borrowings of short-term obligations  (109)   114   (3,628)
Proceeds from issuances of long-term debt  20    –   1,034 
Repayments of long-term debt and other financing obligations  (966)   (1,398)  (1,347)
Cash dividends – common stock  (3,778)   (3,236)  (3,033)
Dividends paid to minority interests  (98)   (41)  (37)
Net (purchases) sales of treasury shares  (2,597)   (1,645)  57 
Redemption of preferred stock of subsidiaries  (140)   (18)  (75)
    
NET CASH USED FOR FINANCING ACTIVITIES
  (7,668)   (6,224)  (7,029)
    
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS
  (124)   58   95 
    
NET CHANGE IN CASH AND CASH EQUIVALENTS
  752    5,025   1,309 
CASH AND CASH EQUIVALENTS AT JANUARY 1
  9,291    4,266   2,957 
    
CASH AND CASH EQUIVALENTS AT DECEMBER 31
 $10,043   $9,291  $4,266 
    
See accompanying Notes to the Consolidated Financial Statements.

FS-32

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
Shares in thousands; amounts in millions of dollars
                          
  2005 2004 2003 
  Shares  Amount   Shares  Amount  Shares  Amount 
    
PREFERRED STOCK
  –  $–    –  $–   –  $– 
    
COMMON STOCK1
                         
Balance at January 1  2,274,032  $1,706    2,274,042  $1,706   2,274,042  $1,706 
Shares issued for Unocal acquisition  168,645   126        –       – 
Conversion of Texaco Inc. acquisition  –   –    (10)  –   –   – 
      
BALANCE AT DECEMBER 31
  2,442,677  $1,832    2,274,032  $1,706   2,274,042  $1,706 
    
CAPITAL IN EXCESS OF PAR1
                         
Balance at January 1     $4,160       $4,002      $3,980 
Shares issued for Unocal acquisition      9,585        –       – 
Stock options and restricted stock units      67        –       – 
Treasury stock transactions      82        158       22 
          
BALANCE AT DECEMBER 31
     $13,894       $4,160      $4,002 
    
RETAINED EARNINGS
                         
Balance at January 1     $45,414       $35,315      $30,942 
Net income      14,099        13,328       7,230 
Cash dividends on common stock      (3,778)       (3,236)      (3,033)
Tax benefit from dividends paid on unallocated ESOP shares and other      3        7       6 
Exchange of Dynegy securities      –        –       170 
          
BALANCE AT DECEMBER 31
     $55,738       $45,414      $35,315 
    
NOTES RECEIVABLE – KEY EMPLOYEES
     $(3)      $–      $– 
    
ACCUMULATED OTHER COMPREHENSIVE LOSS
                         
Currency translation adjustment                         
Balance at January 1     $(140)      $(176)     $(208)
Change during year2
      (5)       36       32 
          
Balance at December 31     $(145)      $(140)     $(176)
Minimum pension liability adjustment                         
Balance at January 1     $(402)      $(874)     $(876)
Change during year      58        472       2 
          
Balance at December 31     $(344)      $(402)     $(874)
Unrealized net holding gain on securities                         
Balance at January 1     $120       $129      $49 
Change during year      (32)       (9)      80 
          
Balance at December 31     $88       $120      $129 
Net derivatives gain (loss) on hedge transactions                         
Balance at January 1     $103       $112      $37 
Change during year2
      (131)       (9)      75 
          
Balance at December 31     $(28)      $103      $112 
          
BALANCE AT DECEMBER 31
     $(429)      $(319)     $(809)
    
DEFERRED COMPENSATION AND BENEFIT PLAN TRUST
                         
DEFERRED COMPENSATION
                         
Balance at January 1     $(367)      $(362)     $(412)
Net reduction of ESOP debt and other      121        (5)      50 
          
BALANCE AT DECEMBER 31
      (246)       (367)      (362)
BENEFIT PLAN TRUST (COMMON STOCK)1
  14,168   (240)   14,168   (240)  14,168   (240)
      
BALANCE AT DECEMBER 31
  14,168  $(486)   14,168  $(607)  14,168  $(602)
    
TREASURY STOCK AT COST1
                         
Balance at January 1  166,912  $(5,124)   135,747  $(3,317)  137,769  $(3,374)
Purchases  52,013   (3,029)   42,607   (2,122)  81   (3)
Issuances – mainly employee benefit plans  (8,935)  283    (11,442)  315   (2,103)  60 
      
BALANCE AT DECEMBER 31
  209,990  $(7,870)   166,912  $(5,124)  135,747  $(3,317)
    
TOTAL STOCKHOLDERS’ EQUITY AT DECEMBER 31
     $62,676       $45,230      $36,295 
    
  
1
Consolidated Balance Sheet
Millions of dollars, except per-share amounts
          
  At December 31 
  2004   2003 
    
ASSETS
         
Cash and cash equivalents $9,291   $4,266 
Marketable securities  1,451    1,001 
Accounts and notes receivable (less allowance: 2004 – $174; 2003 – $179)  12,429    9,722 
Inventories:         
Crude oil and petroleum products  2,324    2,003 
Chemicals  173    173 
Materials, supplies and other  486    472 
      
   2,983    2,648 
Prepaid expenses and other current assets  2,349    1,789 
    
TOTAL CURRENT ASSETS
  28,503    19,426 
Long-term receivables, net  1,419    1,493 
Investments and advances  14,389    12,319 
Properties, plant and equipment, at cost  103,954    100,556 
Less: Accumulated depreciation, depletion and amortization  59,496    56,018 
      
   44,458    44,538 
Deferred charges and other assets  4,277    2,594 
Assets held for sale  162    1,100 
    
TOTAL ASSETS
 $93,208   $81,470 
    
LIABILITIES AND STOCKHOLDERS’ EQUITY
         
Short-term debt $816   $1,703 
Accounts payable  10,747    8,675 
Accrued liabilities  3,410    3,172 
Federal and other taxes on income  2,502    1,392 
Other taxes payable  1,320    1,169 
    
TOTAL CURRENT LIABILITIES
  18,795    16,111 
Long-term debt  10,217    10,651 
Capital lease obligations  239    243 
Deferred credits and other noncurrent obligations  7,942    7,758 
Noncurrent deferred income taxes  7,268    6,417 
Reserves for employee benefit plans  3,345    3,727 
Minority interests  172    268 
    
TOTAL LIABILITIES
  47,978    45,175 
    
Preferred stock (authorized 100,000,000 shares, $1.00 par value; none issued)  –    – 
Common stock (authorized 4,000,000,000 shares, $0.75 par value; 2,274,032,014 and 2,274,042,114 shares issued at December 31, 2004 and 2003, respectively*)  1,706    1,706 
Capital in excess of par value*  4,160    4,002 
Retained earnings  45,414    35,315 
Accumulated other comprehensive loss  (319)   (809)
Deferred compensation and benefit plan trust  (607)   (602)
Treasury stock, at cost (2004 – 166,911,890 shares; 2003 – 135,746,674 shares*)  (5,124)   (3,317)
    
TOTAL STOCKHOLDERS’ EQUITY
  45,230    36,295 
    
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
 $93,208   $81,470 
    
*2003 restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
 
See accompanying Notes to the Consolidated Financial Statements.

FS-27

 
2
Consolidated Statement of Cash FlowsIncludes Unocal balances at December 31, 2005.
Millions of dollars
              
  Year ended December 31 
  2004   2003  2002 
    
OPERATING ACTIVITIES
             
Net income $13,328   $7,230  $1,132 
Adjustments             
Depreciation, depletion and amortization  4,935    5,326   5,169 
Dry hole expense  286    256   288 
Distributions (less) more than income from equity affiliates  (1,422)   (383)  510 
Net before-tax gains on asset retirements and sales  (1,882)   (194)  (33)
Net foreign currency effects  60    199   5 
Deferred income tax provision  (224)   164   (81)
Net decrease in operating working capital  430    162   1,125 
Minority interest in net income  85    80   57 
Cumulative effect of changes in accounting principles  –    196   – 
Gain from exchange of Dynegy preferred stock  –    (365)  – 
Write-down of investments in Dynegy, before tax  –    –   1,796 
(Increase) decrease in long-term receivables  (60)   12   (39)
(Increase) decrease in other deferred charges  (69)   1,646   428 
Cash contributions to employee pension plans  (1,643)   (1,417)  (246)
Other  866    (597)  (168)
    
NET CASH PROVIDED BY OPERATING ACTIVITIES
  14,690    12,315   9,943 
    
INVESTING ACTIVITIES
             
Capital expenditures  (6,310)   (5,625)  (7,597)
Advances to equity affiliate  (2,200)   –   – 
Repayment of loans by equity affiliates  1,790    293   – 
Proceeds from asset sales  3,671    1,107   2,341 
Net (purchases) sales of marketable securities  (450)   153   209 
    
NET CASH USED FOR INVESTING ACTIVITIES
  (3,499)   (4,072)  (5,047)
    
FINANCING ACTIVITIES
             
Net borrowings (payments) of short-term obligations  114    (3,628)  (1,810)
Proceeds from issuances of long-term debt  –    1,034   2,045 
Repayments of long-term debt and other financing obligations  (1,398)   (1,347)  (1,356)
Cash dividends – common stock  (3,236)   (3,033)  (2,965)
Dividends paid to minority interests  (41)   (37)  (26)
Net (purchases) sales of treasury shares  (1,645)   57   41 
Redemption of preferred stock of subsidiaries  (18)   (75)  – 
    
NET CASH USED FOR FINANCING ACTIVITIES
  (6,224)   (7,029)  (4,071)
    
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS
  58    95   15 
    
NET CHANGE IN CASH AND CASH EQUIVALENTS
  5,025    1,309   840 
CASH AND CASH EQUIVALENTS AT JANUARY 1
  4,266    2,957   2,117 
    
CASH AND CASH EQUIVALENTS AT DECEMBER 31
 $9,291   $4,266  $2,957 
    
 
See accompanying Notes to the Consolidated Financial Statements.

FS-28FS-33

  
Consolidated StatementNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Millions of Stockholders’ Equitydollars, except per-share amounts
Shares in thousands; amounts in millions of dollars
                          
  2004   2003  2002 
  Shares  Amount   Shares  Amount  Shares  Amount 
    
PREFERRED STOCK
  –  $–    –  $–   –  $– 
    
COMMON STOCK*
                         
Balance at January 1  2,274,042  $1,706    2,274,042  $1,706   2,274,042  $1,706 
Conversion of Texaco Inc. shares  (10)  –    –   –   –   – 
      
BALANCE AT DECEMBER 31
  2,274,032  $1,706    2,274,042  $1,706   2,274,042  $1,706 
    
CAPITAL IN EXCESS OF PAR*
                         
Balance at January 1     $4,002       $3,980      $3,958 
Treasury stock transactions      158        22       22 
          
BALANCE AT DECEMBER 31
     $4,160       $4,002      $3,980 
    
RETAINED EARNINGS
                         
Balance at January 1     $35,315       $30,942      $32,767 
Net income      13,328        7,230       1,132 
Cash dividends                         
Common stock      (3,236)       (3,033)      (2,965)
Tax benefit from dividends paid on unallocated ESOP shares and other      7        6       8 
Exchange of Dynegy securities      –        170       – 
          
BALANCE AT DECEMBER 31
     $45,414       $35,315      $30,942 
    
ACCUMULATED OTHER COMPREHENSIVE LOSS
                         
Currency translation adjustment                         
Balance at January 1     $(176)      $(208)     $(223)
Change during year      36        32       15 
          
Balance at December 31     $(140)      $(176)     $(208)
Minimum pension liability adjustment                         
Balance at January 1     $(874)      $(876)     $(91)
Change during year      472        2       (785)
          
Balance at December 31     $(402)      $(874)     $(876)
Unrealized net holding gain on securities                         
Balance at January 1     $129       $49      $5 
Change during year      (9)       80       44 
          
Balance at December 31     $120       $129      $49 
Net derivatives gain on hedge transactions                         
Balance at January 1     $112       $37      $3 
Change during year      (9)       75       34 
          
Balance at December 31     $103       $112      $37 
          
BALANCE AT DECEMBER 31
     $(319)      $(809)     $(998)
    
DEFERRED COMPENSATION AND BENEFIT PLAN TRUST
                         
DEFERRED COMPENSATION
                         
Balance at January 1     $(362)      $(412)     $(512)
Net reduction of ESOP debt and other      (5)       50       100 
          
BALANCE AT DECEMBER 31
      (367)       (362)      (412)
BENEFIT PLAN TRUST (COMMON STOCK)*
  14,168   (240)   14,168   (240)  14,168   (240)
      
BALANCE AT DECEMBER 31
  14,168  $(607)   14,168  $(602)  14,168  $(652)
    
TREASURY STOCK AT COST*
                         
Balance at January 1  135,747  $(3,317)   137,769  $(3,374)  139,601  $(3,415)
Purchases  42,607   (2,122)   81   (3)  76   (3)
Issuances – mainly employee benefit plans  (11,442)  315    (2,103)  60   (1,908)  44 
      
BALANCE AT DECEMBER 31
  166,912  $(5,124)   135,747  $(3,317)  137,769  $(3,374)
    
TOTAL STOCKHOLDERS’ EQUITY AT DECEMBER 31
     $45,230       $36,295      $31,604 
    
  
*2003 and 2002 restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
See accompanying Notes to the Consolidated Financial Statements.

FS-29

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

NOTE 1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General ChevronTexacoChevron manages its investments in and provides administrative, financial and management support to U.S. and foreign subsidiaries and affiliates that engage in fully integrated petroleum chemicals and coal miningchemicals operations. In addition, ChevronTexacoChevron holds investments in thebusinesses involving power generation, business.geothermal production, and the mining of coal and other minerals. Collectively, these companies conduct business activities in more thanapproximately 180 countries. Exploration and production (upstream) operations consist of exploring for, developing and producing crude oil and natural gas and also marketing natural gas. Refining, marketing and transportation (downstream) operations relate to refining crude oil into finished petroleum products; marketing crude oil, natural gas and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipeline, marine vessel, motor equipment and rail car. Chemical operations include the manufacture and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant oil additives.
     The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as future confirming events occur.
     The nature of the company’s operations and the many countries in which it operates subject the company to changing economic, regulatory and political conditions. The company does not believe it is vulnerable to the risk of near-term severe impact as a result of any concentration of its activities.
 
Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent owned and variable interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent or for which the company exercises significant influence but not control over policy decisions are accounted for by the equity method. As part of that accounting, the company recognizes gains and losses that arise from the issuance of stock by an affiliate that results in changes in the company’s proportionate share of the dollar amount of the affiliate’s equity currently in income. Deferred income taxes are provided for these gains and losses.

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

intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value. Subsequent recoveries in the carrying value of other investments are reported in “Other comprehensive income.”
     Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the various factors giving rise to the difference. The company’s share of the affiliate’s reported earnings is adjusted quarterly when appropriate to reflect the difference between these allocated values and the affiliate’s historical book values.
 
Derivatives The majority of the company’s activity in commodity derivative instruments is intended to manage the pricefinancial risk posed by physical transactions. For some of this derivative activity, generally limited to large, discrete or infrequently occurring transactions, the company may elect to apply fair value or cash flow hedge accounting. For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s trading activity, gains and losses from the derivative instruments are reported in current income. For derivative instruments relating to foreign currency exposures, gains and losses are reported in current income. Interest rate swaps – hedging a portion of the company’s fixed-rate debt – are accounted for as fair value hedges, whereas interest rate swaps relating to a portion of the company’s floating-rate debt are recorded at fair value on the Consolidated Balance Sheet, with resulting gains and losses reflected in income.
 
Short-Term Investments All short-term investments are classified as available for sale and are in highly liquid debt securities. Those investments that are part of the company’s cash management portfolio and have original maturities of three months or less are reported as “Cash equivalents.” The balance of the short-term investments is reported as “Marketable securities.” Short-term investmentssecurities” and are marked-to-market, with


FS-34

NOTE 1.SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES – Continued
any unrealized gains or losses included in “Other comprehensive income.”
 
InventoriesCrude oil, petroleum products and chemicals are generally stated at cost, using a Last-In, First-Out (LIFO) method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories generally are stated at average cost.
 
Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs are also capitalized for exploratory wells that find commercially produciblehave found crude oil and natural gas reserves thateven if the reserves cannot be classified as proved pending


FS-30

4 NOTE 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued
one or morewhen the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the following: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory wells that are under way or firmly planned, and (3) securing final regulatory approvals for development. Otherwise, well costs are expensed if a determination as to whether proved reserves were found cannot be made within one year following completion of drilling.project. All other exploratory wells and costs are expensed. Refer to Note 2120, beginning on page FS-45FS-49, for additional discussion of accounting for suspended exploratory well costs.
     Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted future net before-tax cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset, significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted future net before-tax cash flows. For proved crude oil and natural gas properties in the United States, the company generally performs the impairment review on an individual field basis. Outside the United States, reviews are performed on a country, concession or field basis, as appropriate. Globally inIn the refining, marketing, transportation and chemical areas, impairment reviews are generally done on the basis of a refinery, a plant, a marketing area or marketing assets by country basis.country. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense.
     Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the
asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value.
     Effective January 1, 2003, the company implemented Financial Accounting Standards Board Statement No. 143,“Accounting for Asset Retirement Obligations (FAS 143),”in which the fair value of a liability for an asset retirement obligation is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 2524, beginning on page FS-53FS-59, relating to asset retirement obligations, which includes additional information on the company’s adoption of FAS 143. Previously, for crude oil, natural gas and coal producing properties, a provision was made through depreciation expense for anticipated abandonment and restoration costs at the end of the property’s useful life.
     Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method by individual field as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed.
     Depreciation and depletion expenses for coal assets are determined using the unit-of-production method as the proved reserves are produced. The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method generally is used to depreciate international plant and equipment and to amortize all capitalized leased assets.
     Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses and from sales as “Other income.”
     Expenditures for maintenance, repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized.
 
Goodwill Goodwill acquired in a business combination is not subject to amortization. As required by Financial Accounting Standards Board (FASB) Statement No. 142,“Goodwill and Other Intangible Assets,”the company will test such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The goodwill arising from the Unocal acquisition is described in more detail in Note 2, beginning on page FS-36.
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.


FS-35

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
NOTE 1.SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES – Continued
     Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For the company’s U.S. and Canadian marketing facilities, the accrual is based in part on the probability that a future remediation commitment will be required. For crude oil, natural gas and coal producing properties, a liability for an asset retirement obligation is made, following FAS 143. Refer to “Properties, Plant and Equipment” in this noteNote 24, beginning on page FS-59, for a discussion of FAS 143.
     For federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares.
     The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured.
 
Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency translations are currently included in income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in the currency translation adjustment in “Stockholders’ equity.”
 
Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which ChevronTexacoChevron has an interest with other producers are generally recognized on the basis of the company’s net working interest (entitlement method). Refer to Note 1615, beginning on page FS-41FS-46, for a discussion of the accounting for buy/sell arrangements.
 
Stock Options and Other Share-Based Compensation At December 31, 2004,Effective July 1, 2005, the company had stock-based employeeadopted the provisions of Financial Accounting Standards Board (FASB) Statement No. 123R,“Share-Based Payment,”(FAS 123R) for its share-based compensation plans, which are described


FS-31

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

4 NOTE 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

more fully in Note 22 beginning on page FS-46.plans. The company accountspreviously accounted for thosethese plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, ““Accounting for Stock Issued to Employees,” (APB 25) and related interpretations.interpretations and disclosure requirements established by FAS 123,“Accounting for Stock-Based Compensation.”
     Refer to Note 22, beginning on page FS-54, for a description of the company’s share-based compensation plans, information related to awards granted under those plans and additional information on the company’s adoption of FAS 123R.
     The following table illustrates the effect on net income and earnings per share as if the company had applied the fair-value-recognitionfair-value recognition provisions of Financial Accounting Standards Board (FASB) Statement No.FAS 123“Accounting to stock options, stock appreciation rights, performance units and restricted stock units for Stock-Based Compensation,”periods prior to stock-based employee compensation:adoption of FAS 123R, and the actual effect on net income and earnings per share for periods after adoption of FAS 123R.
                    
 Year ended December 31  Year ended December 31 
 2004 2003 2002  2005 2004 2003 
      
Net income, as reported $13,328   $7,230 $1,132  $14,099   $13,328 $7,230 
Add: Stock-based employee compensation expense included in reported net income determined under APB No. 25, net of related tax effects1
 10   1  (1)
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects1,2
  (52)   (26)  (47)
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects1
 $81   $42 $16 
Deduct: Total stock-based employee compensation expense determined under fair-valued-based method for awards, net of related tax effects1,2
 $(108)  $(84) $(41)
       
Pro forma net income $13,286   $7,205 $1,084  $14,072   $13,286 $7,205 
       
Earnings per share3,4
   
Net income per share:3,4
   
Basic – as reported $6.30   $3.48 $0.53  $6.58   $6.30 $3.48 
Basic – pro forma $6.28   $3.47 $0.51  $6.56   $6.28 $3.47 
Diluted – as reported $6.28   $3.48 $0.53  $6.54   $6.28 $3.48 
Diluted – pro forma $6.26   $3.47 $0.51  $6.53   $6.26 $3.47 
      
  
1
Costs of stock appreciation rights reported in net income and included inPeriods prior to 2005 conformed to the fair-value method for these rights were $10, $1 and $(1) for 2004, 2003 and 2002, respectively.2005 presentation.
  
2
The fairFair value is estimateddetermined using the Black-Scholes option-pricing model for stock options. Stock appreciation rights are estimated based on the method outlined in SFAS 123 for these instruments.model.
  
3
Per-share amounts in all periods reflectrefl ect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
  
4
The amounts in 2003 include a benefit of $0.08 for the company’s share of a capital stock transaction of its Dynegy Inc. affiliate, which under the applicable accounting rules was recorded directly to the company’s retained earnings and not included in net income for the period.
     Refer to Note 20 beginning on page FS-44 for a discussion of the company’s plan to implement FASB statement No. 123R,“Share-Based Payment,”effective July 1, 2005.

NOTE 2.
SPECIAL ITEMS AND OTHER FINANCIAL INFORMATIONACQUISITION OF UNOCAL CORPORATION

Net income for each period presented includes amounts categorized byOn August 10, 2005, the company as “special items,” to assist in the explanation of the trend of results.
     Listed in the following table are categories of these items and their net increase (decrease) to net income, after related tax effects.
     In 2004, the company recorded special gains of $1,217 from the sale of nonstrategic crude oil and natural gas assets, primarily in the United States and Canada, and a special charge of $55 for a litigation matter.
     In 2003, impairments of $103 and $30, respectively, were recorded for various U.S. and internationalacquired Unocal Corporation (Unocal), an independent oil and gas producing properties, reflecting lower expected recoveryexploration and production company. Unocal’s principal upstream operations are in North America and Asia, including the Caspian region. Also located in Asia are Unocal’s geothermal energy and electrical power businesses. Other activities include ownership interests in proprietary and common carrier pipelines, natural gas storage facilities and mining operations.
     The aggregate purchase price of proved reservesUnocal was approximately $17,300, which included approximately $7,500 cash, 169 million shares of Chevron common stock valued at or about $9,600, and $200 for stock options on approximately 5 million shares and merger-related fees. The value of the common shares was based on the average market price for a write-down5-day period beginning two days before the terms of the acquisition were finalized and announced on July 19, 2005. The issued shares represented approximately 7.5 percent of the number of shares outstanding immediately after the August 10 close. The value of the stock options at the acquisition date was determined using the Black-Scholes option-pricing model.
     A third-party appraisal firm has been engaged to market value forassist the company in the process of determining the fair values



FS-36

NOTE 2.ACQUISITION OF UNOCAL CORPORATION – Continued


of Unocal’s tangible and intangible assets. Initial fair-value estimates were made in the third quarter 2005, and adjustments to those initial estimates were made in the fourth quarter. The company expects the valuation process will be finalized in the first half of 2006. Once completed, the associated deferred tax liabilities will also be adjusted. No significant intangible assets other than goodwill are included in anticipationthe preliminary allocation of sale. Impairments of $123 on downstreamthe purchase price in the table below. No in-process research and development 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.acquired.
     In 2002,The acquisition was accounted for under the company recorded write-downsrules of $1,626Financial Accounting Standards Board (FASB) Statement No. 141,“Business Combinations.”The following table summarizes the preliminary allocation of its investment in Dynegy commonthe purchase price to Unocal’s assets and preferred stock and $136liabilities:
     
  At August 1, 2005 
 
Current assets $3,531 
Investments and long-term receivables  1,647 
Properties  17,288 
Goodwill  4,700 
Other assets  2,055 
 
Total assets acquired  29,221 
 
Current liabilities  (2,365)
Long-term debt and capital leases  (2,392)
Deferred income taxes  (3,743)
Other liabilities  (3,435)
 
Total liabilities assumed  (11,935)
 
Net assets acquired $17,286 
 

     The $4,700 of its investment in its publicly traded Caltex Australia affiliategoodwill is assigned to their respective estimated fair values.the upstream segment. None of the goodwill is deductible for tax purposes. The write-downs were required becausegoodwill represents benefits of the declines inacquisition that are additional to the fair values of the investments below their carrying values were deemedother net assets acquired. The primary reasons for the acquisition and the principal factors that contributed to be other than temporary. Refer to Note 14 beginning on page FS-39 additional information on the company’s investment in Dynegy and Caltex Australia.

     Also in 2002, impairments of $183 were recorded for various U.S. exploration and production properties and $100 for international projects.
              
  Year ended December 31 
  2004   2003  2002 
    
Special Items
             
Asset dispositions             
Exploration and Production             
Continuing operations             
United States  316    77   – 
International  644    32   – 
Discontinued operations             
United States  50    –   – 
International  207    –   – 
Refining, Marketing and Transportation             
United States  –    37   – 
International  –    (24)  – 
      
   1,217    122   – 
Asset impairments/write-offs             
Exploration and Production             
Continuing operations             
United States  –    (103)  (183)
International  –    (30)  (100)
Refining, Marketing and Transportation             
United States  –    –   (66)
International  –    (123)  (136)
All Other             
Other asset write-offs  –    (84)  – 
      
   –    (340)  (485)
    
Tax adjustments  –    118   60 
Environmental remediation provisions  –    (132)  (160)
Restructuring and reorganizations  –    (146)  – 
Merger-related expenses  –    –   (386)
Litigation provisions  (55)   –   (57)
    
Dynegy-related             
Impairments – equity share  –    (40)  (531)
Asset dispositions – equity share  –    –   (149)
Other  –    365   (1,626)
      
   –    325   (2,306)
    
Total Special Items
 $1,162   $(53) $(3,334)
    
     The aggregate effects on income statement categories from special items, including ChevronTexaco’s proportionate share of special items related to equity affiliates, are reflecteda Unocal purchase price that resulted in the following table.


FS-32

4 NOTE 2.SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION – Continued
              
  Year ended December 31 
  2004   2003  2002 
    
Revenues and other income
             
Income (loss) from equity affiliates $–   $179  $(829)
Other income  1,281    (148)  – 
Gain from exchange of Dynegy preferred stock  –    365   – 
    
Total revenues and other income
  1,281    396   (829)
    
Costs and other deductions
             
Operating expenses  85    329   259 
Selling, general and administrative expenses  –    146   180 
Depreciation, depletion and amortization  –    286   298 
Write-down of investments in Dynegy Inc.  –    –   1,796 
Merger-related expenses  –    –   576 
    
Total costs and other deductions
  85    761   3,109 
    
Income from continuing operations before income tax expense
  1,196    (365)  (3,938)
Income tax expense (benefit)  291    (312)  (604)
    
Income from continuing operations
  905    (53)  (3,334)
Income from discontinued operations
  257    –   – 
    
Net income
 $1,162   $(53) $(3,334)
    
     Other financial information isrecognition of goodwill were as follows:
              
  Year ended December 31 
  2004   2003  2002 
    
Total financing interest and debt costs $450   $549  $632 
Less: Capitalized interest  44    75   67 
      
Interest and debt expense $406   $474  $565 
    
Research and development expenses $242   $228  $221 
Foreign currency effects* $(81)  $(404) $(43)
    
 •The “going concern” element of the Unocal businesses, which presents the opportunity to earn a higher rate of return on the assembled collection of net assets than would be expected if those assets were acquired separately. These benefits include upstream growth opportunities in the Asia-Pacific, Gulf of Mexico and Caspian regions. Some of these areas contain operations that are complementary to Chevron’s, and the acquisition is consistent with Chevron’s long-term strategies to grow profitability in its core upstream areas, build new legacy positions and commercialize the company’s large undeveloped natural gas resource base.
*
Includes $(13), $(96)•Cost savings that can be obtained through the capture of operational synergies. The opportunities for cost savings include the elimination of duplicate facilities and $(66)services, high-grading of investment opportunities in 2004, 2003the combined portfolio and 2002, respectively, for the company’s sharesharing of equity affiliates’ foreign currency effects.best practices of the two companies.

     Goodwill recorded in the acquisition is not subject to amortization, but will be tested periodically for impairment as required by FASB Statement No. 142,“Goodwill and Other Intangible Assets.”
     The excessfollowing unaudited pro forma summary presents the results of market value overoperations as if the carrying valueacquisition of inventories for whichUnocal had occurred at the LIFO method is used was $3,036, $2,106beginning of each period:
          
  Year ended December 31 
  2005   2004 
    
Sales and other operating revenues $198,762   $158,471 
Net income  14,967    14,164 
Net income per share of common stock         
Basic $6.68   $6.22 
Diluted $6.64   $6.19 
    

     The pro forma summary uses estimates and $1,571 at December 31, 2004, 2003 and 2002, respectively. Market value is generallyassumptions based on average acquisition costs forinformation available at the year. LIFO profits of $36, $82time. Management believes the estimates and $13 were included in net income forassumptions to be reasonable; however, actual results may differ significantly from this pro forma financial information. The pro forma information does not reflect any synergistic savings that might be achieved from combining the years 2004, 2003operations and 2002, respectively.is not intended to reflect the actual results that would have occurred had the companies actually been combined during the periods presented.

NOTE 3.
COMMON STOCK SPLIT

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

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

“Net decrease
              
  Year ended December 31 
  2005   2004  2003 
    
Net (increase) decrease in operating working capital was composed of the following:             
Increase in accounts and notes receivable $(3,164)  $(2,515) $(265)
(Increase) decrease in inventories  (968)   (298)  115 
(Increase) decrease in prepaid expenses and other current assets  (54)   (76)  261 
Increase in accounts payable and accrued liabilities  3,851    2,175   242 
Increase (decrease) in income and other taxes payable  281    1,144   (191)
    
Net (increase) decrease in operating working capital $(54)  $430  $162 
    
Net cash provided by operating activities includes the following cash payments for interest and income taxes:             
Interest paid on debt (net of capitalized interest) $455   $422  $467 
Income taxes $8,875   $6,679  $5,316 
    
Net (purchases) sales of marketable securities consisted of the following gross amounts:             
Marketable securities purchased $(918)  $(1,951) $(3,563)
Marketable securities sold  1,254    1,501   3,716 
    
Net sales (purchases) of marketable securities $336   $(450) $153 
    

     The 2005 “Net increase in operating working capital” is composedincluded a reduction of $20 for excess income tax benefits associated with stock options exercised since July 1, 2005, in accordance with the following:cash-flows classifi cation requirements of



FS-37

Notes to the Consolidated Financial Statements
              
  Year ended December 31 
  2004   2003  2002 
    
Increase in accounts and notes receivable $(2,515)  $(265) $(1,135)
(Increase) decrease in inventories  (298)   115   185 
(Increase) decrease in prepaid expenses and other current assets  (76)   261   92 
Increase in accounts payable and accrued liabilities  2,175    242   1,845 
Increase (decrease) in income and other taxes payable  1,144    (191)  138 
    
Net decrease in operating working capital $430   $162  $1,125 
    
Net cash provided by operating activities includes the following cash payments for interest and income taxes:             
Interest paid on debt (net of capitalized interest) $422   $467  $533 
Income taxes $6,679   $5,316  $2,916 
    
Net (purchases) sales of marketable securities consist of the following gross amounts:             
Marketable securities purchased $(1,951)  $(3,563) $(5,789)
Marketable securities sold  1,501    3,716   5,998 
    
Net (purchases) sales of marketable securities $(450)  $153  $209 
    
Millions of dollars, except per-share amounts
NOTE 3.INFORMATION RELATING TO THE CONSOLIDATED
STATEMENT OF CASH FLOWS— Continued
      
FAS 123R,“Share-Based Payment.”This amount was offset by an equal amount in “Net purchases of treasury shares.” Refer to Note 22, beginning on page FS-54, for additional information related to the company’s adoption of FAS 123R.
     The “Net (purchases) sales of treasury shares” in 2005 and 2004 included purchases of $3,029 and $2,122, respectively, related to the company’s common stock repurchase programs and share-based compensation plans, which were partially offset by the issuance of shares for the exercise of stock options.
     The 2003 “Net cash provided by operating activities” included an $890 “Decrease in other deferred charges” and a decrease of the same amount in “Other” related to balance sheet netting of certain pension-related asset and liability accounts, in accordance with the requirements of Financial Accounting Standards Board (FASB) Statement No. 87,“Employers’ Accounting for Pensions.”
     The “Net (purchases) sales“cash portion of treasury shares” in 2004 included share repurchasesUnocal acquisition, net of $2.1 billion relatedUnocal cash received” represents the purchase price, net of $1,600 of cash received. The aggregate purchase price of Unocal was $17,300. Refer to Note 2 starting on page FS‑36 for additional discussion of the company’s common stock repurchase program, which were partially offset by the issuance of shares for the exercise of stock options.Unocal acquisition.
     The major components of “Capital expenditures” and the reconciliation of this amount to the reported capital and exploratory expenditures, including equity affiliates, presented in MD&AManagement’s Discussion and Analysis, beginning on page FS-13, are presented in the following table.table:



FS-33

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

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

                      
 Year ended December 31  Year ended December 31 
 2004 2003 2002  2005 2004 2003 
       
Additions to properties, plant and equipment1
 $5,798   $4,953 $6,262  $ 8,154   $ 5,798 $ 4,953 
Additions to investments 303   687 1,138  459   303 687 
Current-year dry hole expenditures 228   132 252  198   228 132 
Payments for other liabilities and assets, net  (19)   (147)  (55)  (110)   (19)  (147)
       
Capital expenditures 6,310   5,625 7,597  8,701   6,310 5,625 
Expensed exploration expenditures 412   315 303  517   412 315 
Payments of long-term debt and other financing obligations, net 31    2862 2 
Assets acquired through capital   
lease obligations and other financing obligations 164   31  2862
       
Capital and exploratory expenditures, excluding equity affiliates 6,753   6,226 7,902  9,382   6,753 6,226 
Equity in affiliates’ expenditures 1,562   1,137 1,353  1,681   1,562 1,137 
       
Capital and exploratory expenditures, including equity affiliates $8,315   $7,363 $9,255  $ 11,063   $ 8,315 $ 7,363 
      
  
1
Net of noncash additions of $435 in 2005, $212 in 2004 and $1,183 in 2003 and $195 in 2002.2003.
  
2
Includes deferred payment of $210 related to the 1993 acquisition of the company’s interest in the Tengizchevroil joint venture.

NOTE 5.4.
SUMMARIZED FINANCIAL DATA – CHEVRON U.S.A. INC.
Chevron U.S.A. Inc. (CUSA) is a major subsidiary of ChevronTexacoChevron Corporation. CUSA and its subsidiaries manage and operate most of ChevronTexaco’sChevron’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.Chevron. CUSA also holds ChevronTexaco’sChevron’s investments in the ChevronPhillipsChevron Phillips Chemical Company LLC (CPChem) joint venture and Dynegy Inc. (Dynegy), which are accounted for using the equity method.
     During 2003, and 2002, ChevronTexacoChevron implemented legal reorganizations in which certain ChevronTexacoChevron subsidiaries transferred assets to or under CUSA and other ChevronTexacoChevron companies were merged with and into CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the following table gives retroactive effect to the reorganization in a manner similar to a pooling of interests,reorganizations, with all periods presented as if the companies had always been combined and the reorganizationreorganizations had occurred on January 1, 2002.2003. However, the financial information included in this table may not reflect the financial position and operating results in the future or the historical results in the periods presented had the reorganizationreorganizations actually occurred on January 1, 2002.

2003.
                      
 Year ended December 31  Year ended December 31 
 2004 2003 2002  2005 2004 2003 
       
Sales and other operating revenues $108,351   $82,760 $66,835  $ 138,296   $ 108,351 $ 82,760 
Total costs and other deductions 102,180   78,399 68,526  132,180   102,180 78,399 
Net income (loss)* 4,773   3,083  (1,895)
Net income* 4,693   4,773 3,083 
      
  
*2003 net income includes a charge of $323 for the cumulative effect of changes in accounting principles.
              
 At December 31  At December 31 
 2004 2003  2005 2004 
       
Current assets $23,147   $15,539  $ 27,878   $ 23,147 
Other assets* 19,961   21,348 
Other assets 20,611   19,961 
Current liabilities 17,044   13,122  20,286   17,044 
Other liabilities 12,533   14,136  12,897   12,533 
Net equity 13,531   9,629  15,306   13,531 
      
 
Memo: Total debt $8,349 $9,091  $ 8,353 $ 8,349 
*Includes assets held for sale of $1,052 at December 31, 2003.
     CUSA’s net loss of $1,895 for 2002 included net charges of $2,555 for asset write-downs and dispositions, of which $2,306 was related to Dynegy.

NOTE 6.5.
SUMMARIZED FINANCIAL DATA – CHEVRON TRANSPORT CORPORATION LTD.
Chevron Transport Corporation Ltd. (CTC), incorporated in Bermuda, is an indirect, wholly owned subsidiary of ChevronTexacoChevron Corporation. CTC is the principal operator of ChevronTexaco’sChevron’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 ChevronTexacoChevron companies. ChevronTexacoChevron Corporation has guaranteed this subsidiary’s obligations in connection with certain debt securities issued by a third party. Summarized financial information for CTC and its consolidated subsidiaries is presented in the following table:



FS-38

              
  Year ended December 31 
  2004   2003  2002 
    
Sales and other operating revenues $660   $601  $850 
Total costs and other deductions  495    535   922 
Net income (loss)  160    50   (79)
    
          
  At December 31 
  2004   2003 
    
Current assets $292   $116 
Other assets  219    312 
Current liabilities  67    96 
Other liabilities  278    243 
Net equity  166    89 
    
NOTE 5.SUMMARIZED FINANCIAL DATA – CHEVRON
TRANSPORT CORPORATION LTD. – Continued
      
     During 2004, CTC’s paid-in capital decreased by $85 from capital settlements.
              
  Year ended December 31 
  2005   2004  2003 
    
Sales and other operating revenues $640   $660  $601 
Total costs and other deductions  509    495   535 
Net income  113    160   50 
    
          
  At December 31 
  2005   2004 
    
Current assets $358   $292 
Other assets  283    219 
Current liabilities  119    67 
Other liabilities  243    278 
Net equity  279    166 
    
     There were no restrictions on CTC’s ability to pay dividends or make loans or advances at December 31, 2004.2005.

NOTE 7.6.
STOCKHOLDERS’ EQUITY
Retained earnings at December 31, 20042005 and 2003,2004, included approximately $3,950$5,000 and $1,300,$3,950, respectively, for the company’s share of undistributed earnings of equity affiliates.
     At December 31, 2004,2005, about 151142 million shares of ChevronTexaco’sChevron’s common stock remainremained available for issuance



FS-34

4 NOTE 7.STOCKHOLDERS’ EQUITY – Continued
from the 160 million shares that were reserved for issuance under the ChevronTexacoChevron Corporation Long-Term Incentive Plan (LTIP), as amended and restated, which was approved by the stockholders in 2004. In addition, approximately 622561 thousand shares remain available for issuance from the 800 thousand shares of the company’s common stock that were reserved for awards under the ChevronTexacoChevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan (Non-Employee Directors’ Plan), which was approved by stockholders in 2003.
Refer to Note 326, on page FS-33FS-62, for a discussion of the company’s common stock split.split in 2004.

NOTE 8.7.
FINANCIAL AND DERIVATIVE INSTRUMENTS
Commodity Derivative Instruments ChevronTexacoChevron is exposed to market risks related to price volatility of crude oil, refined products, electricity, natural gas, natural gas liquids and refinery feedstock.feedstocks.
     The company uses financial derivative commodity instruments to manage this exposurethese exposures on a small portion of its activity, including: firm commitments and anticipated transactions for the purchase or sale of crude oil; feedstock purchases for company refineries; crude oil and refined products inventories; and fixed-price contracts to sell natural gas and natural gas liquids. The company also uses financial derivative commodity instruments for limited trading purposes.
     The company maintains a policy of requiring that anuses International Swaps and DerivativesDealers Association Agreementagreements to govern derivative contracts with certain counterparties to mitigate credit risk. Depending on the nature of the derivative transaction,transactions, 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”net marked-to-market exposure represents the netting of the positive and negative exposures with that counterparty and is a reasonable measure of the company’s credit risk. It is the company’s policy to userisk exposure. The company also uses other netting agreements with certain counterparties with which it conducts significant transactions.transactions to mitigate credit risk.
     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,”net” and “Deferred credits and other noncurrent obligations.” Gains and losses on the company’s risk management activities are reported as either “Sales and other operating revenues” or “Purchased crude oil and products,” whereas trading gains and losses are reported as “Other income.” These activities are reported under “Operating activities” in the Consolidated Statement of Cash Flows.
      
Foreign Currency The company enters into forward exchange contracts, generally with terms of 180 days or less, to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments, forecasted to occur within 180 days. The forward exchange contracts are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.

     The fair values of the outstanding contracts are reported on the Consolidated Balance Sheet as “Accounts and notes receivable” or “Accounts payable,” with gains and losses reported as “Other income.” These activities are reported under “Operating activities” in the Consolidated Statement of Cash Flows.
      
Interest Rates The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements are based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts. Interest rate swaps related to a portion of the company’s fixed-rate debt are accounted for as fair value hedges, whereas interest rate swaps related to a portion of the company’s floating-rate debt are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.
     During 2004, four new swaps relating to a portion of the company’s fixed-rate debt were initiated. At year-end 2004, the interest rate swaps outstanding related to fixed-rate debt, and their weighted average maturity was approximately three years.
Fair values of the interest rate swaps are reported on the Consolidated Balance Sheet as “Accounts and notes receivable” or “Accounts payable,” with gains and losses reported directly in income as part of “Interest and debt expense.” These activities are reported under “Operating activities” in the Consolidated Statement of Cash Flows.
      
Fair Value Fair values are derived either from quoted market prices or, if not available, the present value of the expected cash flows. The fair values reflect the cash that would have been received or paid if the instruments were settled at year-end.


FS-39

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
NOTE 7.FINANCIAL AND DERIVATIVE
INSTRUMENTS – Continued
     Long-term debt of $5,815$7,424 and $7,229$5,815 had estimated fair values of $6,444$7,945 and $7,709$6,444 at December 31, 20042005 and 2003,2004, respectively.
     For interest rate swaps, the notional principal amounts of $1,665$1,400 and $665$1,665 had estimated fair values of $36$(10) and $65$36 at December 31, 20042005 and 2003,2004, respectively.
     The company holds cash equivalents and U.S. dollar marketable securities in domestic and offshore portfolios. Eurodollar bonds, floating-rate notes, time deposits and commercial paper are the primary instruments held. Cash equivalents and marketable securities had fair values of $8,789$8,995 and $3,803$8,789 at December 31, 20042005 and 2003,2004, respectively. Of these balances, $7,338$7,894 and $2,803$7,338 at the respective year-ends were classified as cash equivalents that had average maturities under 90 days. The remainder, classified as marketable securities, had average maturities of approximately 2.32 years.
     For the financial and derivative instruments discussed above, there was not a material change in market risk from that presented in 2003.2004.
      
Concentrations of Credit RisRiskkThe company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables. The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings. This diversified investment policy limits the company’s exposure both to credit risk and to concentrations of credit risk. Similar standards of diversity and creditworthiness are applied to the company’s counterparties in derivative instruments.
     The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s


FS-35

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

4 NOTE 8.FINANCIAL AND DERIVATIVE INSTRUMENTS – Continued

broad customer base worldwide. As a consequence, concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered sufficient, requiring Letters of Credit are theis a principal security obtainedmethod used to support lines of credit.sales to customers.
      
Investment in Dynegy Notes and Preferred Stock At the beginning of 2004,December 31, 2005, the company held investmentsan investment in $223 face value of Dynegy Junior Unsecured Subordinated Notes due 2016 and $400 face value of Dynegy Series C Convertible Preferred Stock, with a stated maturity date of 2033.
     The Junior Notes were redeemed at face value during 2004, and gains of $54 were recorded for the difference between the face amounts and the carrying values at the time of redemption. The face value of the company’s investment in the Series C preferred stock at December 31, 2004, was $400. The stock iswas recorded at its fair value, which was estimated to be $370$360 at December 31, 2004. Future temporarythe end of 2005.
     Temporary changes in the estimated fair value of the preferred stock will beare reported in “Other comprehensive income.” However, if any future decline in fair value is deemed to be other than temporary, a charge against income in the period would be recorded. Dividends payable on the preferred stock are recognized in income each period.

NOTE 9.8.
OPERATING SEGMENTS AND GEOGRAPHIC DATA
Although each subsidiary of ChevronTexacoChevron is responsible for its own affairs, ChevronTexacoChevron Corporation manages its investments in these subsidiaries and their affiliates. For this purpose, the investments are grouped as follows: upstream – exploration and production; downstream – refining, marketing and transportation; chemicals; and all other. The first three of these groupings represent the company’s “reportable segments” and “operating segments” as defined in FAS 131,“Disclosures About Segments of an Enterprise and Related Information.”
     The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) (terms as defined in FAS 131). The CODM is the company’s Executive Committee, a committee of senior officers that includes the Chief Executive Officer and that in turn reports to the Board of Directors of ChevronTexacoChevron Corporation.
     The operating segments represent components of the company as described in FAS 131 terms that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and to assess their performance; and (c) for which discrete financial information is available.
     Segment managers for the reportable segments are directly accountable to and maintain regular contact with the company’s CODM to discuss the segment’s operating activities and financial performance. The CODM approves annual capital and exploratory budgets at the reportable segment level, and also approvesas well as reviews capital and exploratory funding for major projects and approves major changes to the annual capital and exploratory budgets. However, business-unit managers within the operating segments are directly responsible for decisions relating to project implementation and all

other matters connected with daily operations. Company officers who are members of the Executive Committee also have individual management responsibilities and participate in other committees for purposes other than acting as the CODM.
     “All Other” activities include the company’s interest in Dynegy, coal mining operations of coal and other minerals, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities and technology companies.
     The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States).
      
Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All Other.” Merger-related expenses in 2002 were also included in “All



FS-40

NOTE 8.OPERATING SEGMENTS AND
GEOGRAPHIC DATA – Continued
“All Other.” After-tax segment income (loss) from continuing operations is presented in the following table:
                    
 Year ended December 31  Year ended December 31 
 2004 2003 2002  2005 2004 2003 
       
Income From Continuing Operations
      
Upstream – Exploration and Production
      
United States $3,868   $3,160 $1,703  $4,168   $3,868 $3,160 
International 5,622   3,199 2,823  7,556   5,622 3,199 
       
Total Exploration and Production
 9,490   6,359 4,526 
Total Upstream
 11,724   9,490 6,359 
       
Downstream – Refining, Marketing and Transportation
      
United States 1,261   482  (398) 980   1,261 482 
International 1,989   685 31  1,786   1,989 685 
       
Total Refining, Marketing and Transportation
 3,250   1,167  (367)
Total Downstream
 2,766   3,250 1,167 
       
Chemicals
      
United States 251   5 13  240   251 5 
International 63   64 73  58   63 64 
       
Total Chemicals
 314   69 86  298   314 69 
       
Total Segment Income
 13,054   7,595 4,245  14,788   13,054 7,595 
   
All Other
      
Interest expense  (257)   (352)  (406)  (337)   (257)  (352)
Interest income 129   75 72  266   129 75 
Other 108   64  (2,423)  (618)  108 64 
Merger-related expenses –   –  (386)
      
Income From Continuing Operations
 13,034   7,382 1,102  14,099   13,034 7,382 
Income From Discontinued Operations
 294   44 30  –   294 44 
Cumulative effect of changes in accounting principles –    (196) –  –   –  (196)
       
Net Income
 $13,328   $7,230 $1,132  $14,099   $13,328 $7,230 
      


FS-36

4NOTE 9.OPERATING SEGMENTS AND GEOGRAPHIC DATA – Continued
Segment Assets Segment assets do not include intercompany investments or intercompany receivables. Segment assets at year-end 20042005 and 20032004 follow:
            
 At December 31  At December 31 
 2004 2003  2005 2004 
       
Upstream – Exploration and Production
      
United States $11,869   $12,501  $19,006   $11,869 
International 31,239   28,520  46,501   31,239 
Goodwill 4,636   – 
       
Total Exploration and Production
 43,108   41,021 
Total Upstream
 70,143   43,108 
       
Downstream – Refining, Marketing and Transportation
      
United States 10,091   9,354  12,273   10,091 
International 19,415   17,627  22,294   19,415 
       
Total Refining, Marketing and Transportation
 29,506   26,981 
Total Downstream
 34,567   29,506 
       
Chemicals
      
United States 2,316   2,165  2,452   2,316 
International 667   662  727   667 
       
Total Chemicals
 2,983   2,827  3,179   2,983 
       
Total Segment Assets
 75,597   70,829  107,889   75,597 
       
All Other*
      
United States 11,746   6,644  9,234   11,746 
International 5,865   3,997  8,710   5,865 
       
Total All Other
 17,611   10,641  17,944   17,611 
       
Total Assets – United States
 36,022   30,664  42,965   36,022 
Total Assets – International
 57,186   50,806  78,232   57,186 
Goodwill
 4,636   – 
       
Total Assets
 $93,208   $81,470  $125,833   $93,208 
      
  
*All Other assets consist primarily of worldwide cash, cash equivalents and marketable securities, real estate, information systems, the company’s investment in Dynegy, coal mining operations of coal and other minerals, power generation businesses, technology companies, and assets of the corporate administrative functions.
 
Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2005, 2004 2003 and 20022003 are presented in the following table. Products are transferred between operating segments at internal product values that approximate market prices.
     Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products, such as gasoline, jet fuel, gas oils, kerosene, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the transportation and trading of crude oil and refined products. Revenues for the chemicals segment are derived primarily from the manufacture and sale of additives for lubricants and fuel. “All Other” activities include revenues from coal mining operations of coal and other minerals, power generation businesses, insurance operations, real estate activities and technology companies.
     Other than the United States, the only country where ChevronTexaco generatesin which Chevron recorded significant revenues iswas the United Kingdom, wherewith revenues amounted toof $15,296, $13,985 and $12,121 in 2005, 2004 and $10,816 in 2004, 2003, and 2002, respectively.
              
  Year ended December 31 
  2004   2003  2002 
    
Upstream – Exploration and Production
             
United States $8,242   $6,842  $4,923 
Intersegment  8,121    6,295   4,217 
    
Total United States  16,363    13,137   9,140 
    
International  7,246    7,013   5,360 
Intersegment  10,184    8,142   8,301 
    
Total International  17,430    15,155   13,661 
    
Total Exploration and Production
  33,793    28,292   22,801 
    
Downstream – Refining, Marketing and Transportation
             
United States  57,723    44,701   33,881 
Excise taxes  4,147    3,744   3,990 
Intersegment  179    225   163 
    
Total United States  62,049    48,670   38,034 
    
International  67,944    52,486   45,759 
Excise taxes  3,810    3,342   3,006 
Intersegment  87    46   38 
    
Total International  71,841    55,874   48,803 
    
Total Refining, Marketing and Transportation
  133,890    104,544   86,837 
    
Chemicals
             
United States  347    323   323 
Intersegment  188    129   109 
    
Total United States  535    452   432 
    
International  747    677   638 
Excise taxes  11    9   10 
Intersegment  107    83   68 
    
Total International  865    769   716 
    
Total Chemicals
  1,400    1,221   1,148 
    
All Other
             
United States  551    338   413 
Intersegment  431    121   105 
    
Total United States  982    459   518 
    
International  97    100   37 
Intersegment  82    4   – 
    
Total International  179    104   37 
    
Total All Other
  1,161    563   555 
    
Segment Sales and Other Operating Revenues
             
United States  79,929    62,718   48,124 
International  90,315    71,902   63,217 
    
Total Segment Sales and Other Operating Revenues
  170,244    134,620   111,341 
Elimination of intersegment sales  (19,379)   (15,045)  (13,001)
    
Total Sales and Other Operating Revenues
 $150,865   $119,575  $98,340 
    


FS-37FS-41

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
NOTE 8.OPERATING SEGMENTS AND
GEOGRAPHIC DATA — Continued
              
  Year ended December 31 
  2005   2004  2003 
    
Upstream — Exploration and Production
             
United States $16,044   $8,242  $6,842 
Intersegment  8,651    8,121   6,295 
    
Total United States  24,695    16,363   13,137 
    
International  10,190    7,246   7,013 
Intersegment  13,652    10,184   8,142 
    
Total International  23,842    17,430   15,155 
    
Total Upstream
  48,537    33,793   28,292 
    
Downstream — Refining, Marketing and Transportation
             
United States  73,721    57,723   44,701 
Excise taxes  4,521    4,147   3,744 
Intersegment  535    179   225 
    
Total United States  78,777    62,049   48,670 
    
International  83,223    67,944   52,486 
Excise taxes  4,184    3,810   3,342 
Intersegment  14    87   46 
    
Total International  87,421    71,841   55,874 
    
Total Downstream
 ��166,198    133,890   104,544 
    
Chemicals
             
United States  343    347   323 
Intersegment  241    188   129 
    
Total United States  584    535   452 
    
International  760    747   677 
Excise taxes  14    11   9 
Intersegment  131    107   83 
    
Total International  905    865   769 
    
Total Chemicals
  1,489    1,400   1,221 
    
All Other
             
United States  597    551   338 
Intersegment  514    431   121 
    
Total United States  1,111    982   459 
    
International  44    97   100 
Intersegment  26    16   4 
    
Total International  70    113   104 
    
Total All Other
  1,181    1,095   563 
    
Segment Sales and Other Operating Revenues
             
United States  105,167    79,929   62,718 
International  112,238    90,249   71,902 
    
Total Segment Sales and Other Operating Revenues
  217,405    170,178   134,620 
Elimination of intersegment sales  (23,764)   (19,313)  (15,045)
    
Total Sales and Other Operating Revenues*
 $ 193,641   $ 150,865  $ 119,575 
    
  
*		NotesIncludes buy/sell contracts of $23,822 in 2005, $18,650 in 2004 and $14,246 in 2003. Substantially all of the amounts in each period relates to the Consolidated Financial Statements
Millionsdownstream segment. Refer to Note 15, beginning on page FS-46, for a discussion of dollars, except per-share amounts
the company’s accounting for buy/sell contracts.

4NOTE 9.OPERATING SEGMENTS AND GEOGRAPHIC DATA – Continued

Segment Income Taxes Segment income tax expenses for the years 2005, 2004 2003 and 20022003 are as follows:
                      
 Year ended December 31  Year ended December 31 
 2004 20031 2002  2005 2004 20031 
       
Upstream – Exploration and Production
   
Upstream — Exploration and Production
   
United States $2,308   $1,853 $854  $2,330   $2,308 $1,853 
International 5,041   3,831 3,415  8,440   5,041 3,831 
       
Total Exploration and Production
 7,349   5,684 4,269 
Total Upstream
 10,770   7,349 5,684 
       
Downstream – Refining, Marketing and Transportation
   
Downstream — Refining, Marketing and Transportation
   
United States 739   300  (254) 575   739 300 
International 442   275 138  576   442 275 
       
Total Refining, Marketing and Transportation
 1,181   575  (116)
Total Downstream
 1,151   1,181 575 
       
Chemicals
      
United States 47    (25)  (17) 99   47  (25)
International 17   6 17  25   17 6 
       
Total Chemicals
 64    (19) –  124   64  (19)
       
All Other
  (1,077)   (946)  (1,155)  (947)   (1,077)  (946)
       
Income Tax Expense From Continuing Operations2
 $7,517   $5,294 $2,998  $ 11,098   $ 7,517 $ 5,294 
      
  
1
See Note 2524, beginning on page FS-53FS-59, for information concerning the cumulative effect of changes in accounting principles due to the adoption of FAS 143,“Accounting for Asset Retirement Obligations.”
  
2
Income tax expense of $100 $50 and $26$50 related to discontinued operations for 2004 2003 and 2002,2003, respectively, is not included.
 
Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 1413, beginning on page FS-39.FS-44. Information related to properties, plant and equipment by segment is contained in Note 1514, on page FS-41.FS-46.

NOTE 10.9.
LITIGATION
The companyChevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive.
     The company Chevron is a party to more than 70 lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners, related to the use of MTBE in certain oxygenated gasolines and the alleged seepage of MTBE into groundwater. Resolution of these actions may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future.
     The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company does not use MTBE in the manufacture of gasoline in the United States and there are no detectable levels of MTBE in that gasoline.States.

NOTE 11.10.
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 paymentspay-



FS-42

NOTE 10.LEASE COMMITMENTS – Continued
ments on such leases are recorded as expense. Details of the capitalized leased assets are as follows:
            
 At December 31  At December 31 
 2004 2003  2005 2004 
       
Exploration and Production $277   $246  $442   $277 
Refining, Marketing and Transportation 842   842  837   842 
       
Total 1,119   1,088  1,279   1,119 
Less: Accumulated amortization 690   642  745   690 
       
Net capitalized leased assets $429   $446  $534   $429 
      

     Rental expenses incurred for operating leases during 2005, 2004 2003 and 20022003 were as follows:
                    
 Year ended December 31  Year ended December 31 
 2004 2003 2002  2005 2004 2003 
       
Minimum rentals $2,093   $1,567 $1,270  $2,102   $2,093 $1,567 
Contingent rentals 7   3 4  6   7 3 
       
Total 2,100   1,570 1,274  2,108   2,100 1,570 
Less: Sublease rental income 40   48 53  43   40 48 
       
Net rental expense $2,060   $1,522 $1,221  $2,065   $2,060 $1,522 
      

     Contingent rentals are based on factors other than the passage of time, principally sales volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, renewal options ranging up to 25 years, and options to purchase the leased property during or at the end of the initial or renewal lease period for the fair market value or other specified amount at that time.
     At December 31, 2004,2005, the estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases, which at inception had a noncancelablenon-cancelable term of more than one year, were as follows:
          
  At December 31 
  Operating   Capital 
  Leases   Leases 
    
Year: 2005 $390   $83 
2006  338    74 
2007  280    62 
2008  239    51 
2009  236    52 
Thereafter  749    562 
    
Total $2,232   $884 
      
Less: Amounts representing interest and executory costs       (292)
    
Net present values       592 
Less: Capital lease obligations included in short-term debt       (353)
    
Long-term capital lease obligations      $239 
    
            
    At December 31 
    Operating   Capital 
    Leases   Leases 
    
Year: 2006 $507   $106 
  2007  444    87 
  2008  401    76 
  2009  349    77 
  2010  284    58 
  Thereafter  932    564 
    
Total   $2,917   $968 
      
Less: Amounts representing interest and executory costs       (277)
    
Net present values       691 
Less: Capital lease obligations included in short-term debt       (367)
    
Long-term capital lease obligations      $324 
    



FS-38

4NOTE 12.RESTRUCTURING AND REORGANIZATION COSTS

NOTE 12.11.
RESTRUCTURING AND REORGANIZATION COSTS
In connection with the Unocal acquisition, the company implemented a restructuring and reorganization program as part of the effort to capture the synergies of the combined companies. The program is expected to be substantially completed by the end of 2006 and is aimed at eliminating redundant operations, consolidating offices and facilities, and sharing common services and functions.
     As part of the restructuring and reorganization, approximately 700 positions have been preliminarily identified for elimination. Most of the positions are in the United States and relate primarily to corporate and upstream executive and administrative functions. By year-end 2005, approximately 250 of these employees had been terminated.
     An accrual of $106 was established as part of the purchase-price allocation for Unocal. Payments against the accrual in 2005 were $62. The balance at year-end 2005 was classified as a current liability on the Consolidated Balance Sheet. Adjustments to the accrual may occur in future periods as the implementation plans are finalized and estimates are refined.
     
Amounts before tax 2005 
 
Balance at August 1 $106 
Payments  (62)
 
Balance at December 31 $44 
 
     As a result of various other reorganizations and restructurings across several businesses and corporate departments, the company recorded before-tax charges of $258 ($146 after tax) during 2003 for estimated termination benefits for approximately 4,500 employees. Nearly half of the liability related to the global downstream segment. Substantially all of the employee reductions are expected to occurhad occurred by the end of 2005.
     At the beginning of 2004, a $100 liability remained for employee severance charges recorded in 2002 and 2001 associated with the merger between Chevron Corporation and Texaco Inc. The balance related primarily to deferred payment options elected by certain employees who were terminated before the end of 2003. Approximately $80 of the liability was paid during 2004 and the remainder in January 2005.early 2006.
     Activity for the company’s liability related to these other reorganizations and restructurings in 2004 is summarized in the following table:
            
Amounts before tax 2004 2003  2005 2004 
       
Balance at January 1 $240   $6  $119   $240 
Additions 27   258 
Additions/adjustments  (10)  27 
Payments  (148)   (24)  (62)   (148)
       
Balance at December 31 $119   $240  $47   $119 
      

     Substantially all of the balance at December 31, 2004, related to employee severance costs that were part of a presumed ongoing benefit arrangement under applicable accounting rules in FAS 146,“Accounting for Costs Associated with Exit or Disposal Activities,”paragraph 8, footnote 7. Therefore, the company accounts for severance costs in accordance with FAS 88,“Employers’ Accounting for Settlements and Curtailments of Defined Pension Plans and for Termination Benefits.”

     At December 31, 2004,2005, the amount was categorizedclassified as a current accrued liability on the Consolidated Balance Sheet and the associated charges or credits during the period were categorized as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income.



FS-43

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

NOTE 13.12.
ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS
At December 31, 2004, and December 31, 2003, the company classified $162 and $1,100, respectively, of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. Assets in this category at the end of 2004 related to a group of service stations. These assets are expected to be disposed of in 2005.stations outside the United States.
     Summarized income statement information relating to discontinued operations is as follows:
              
  Year ended December 31 
  2004   2003  2002 
    
Revenues and other income $635   $485  $376 
Income from discontinued operations before income tax expense  394    94   56 
Income from discontinued operations, net of tax  294    44   30 
    

              
 Year ended December 31 
  2005   2004  2003 
    
Revenues and other income $–   $635  $485 
Income from discontinued operations before income tax expense  –    394   94 
Income from discontinued operations, net of tax  –    294   44 
    

     Included in the 2004 after-tax amount were gains totaling $257 related to the sale of a Canadian natural-gas processing business, a wholly owned subsidiary in the Democratic Republic of the Congo and certain producing properties in the Gulf of Mexico.

     Not all assets sold or to be disposed of are classified as discontinued operations, mainly because the cash flows from the assets were not/not, or will not be, eliminated from the ongoing operations of the company.

NOTE 14.13.
INVESTMENTS AND ADVANCES
Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other investments accounted for at or below cost, are as follows:
                                    
 Investments and Advances Equity in Earnings  Investments and Advances Equity in Earnings 
 At December 31  Year ended December 31  At December 31 Year ended December 31 
 2004 2003 2004 2003 2002  2005 2004 2005 2004 2003 
       
Upstream – Exploration and Production
   
Upstream — Exploration and Production
   
Tengizchevroil $4,725 $3,363   $950 $611 $490  $5,007 $4,725   $1,514 $950 $611 
Hamaca 1,189 836   390 98 45 
Other 1,177 991   246 200 116  679 341   139 148 155 
       
Total Exploration and Production 5,902 4,354   1,196 811 606 
Total Upstream 6,875 5,902   2,043 1,196 811 
       
Downstream – Refining, Marketing and Transportation
   
LG-Caltex Oil Corporation 1,820 1,561   296 107 46 
Downstream — Refining, Marketing and Transportation
   
GS Caltex Corporation 1,984 1,820   320 296 107 
Caspian Pipeline Consortium 1,039 1,026   140 52 66  1,014 1,039   101 140 52 
Star Petroleum Refining Company Ltd. 663 457   207 8  (25) 709 663   81 207 8 
Caltex Australia Ltd. 263 118   173 13  (156) 435 263   214 173 13 
Colonial Pipeline Company 565 –   13 – – 
Other 1,125 1,069   143 100 110  1,562 1,125   273 143 100 
       
Total Refining, Marketing and Transportation 4,910 4,231   959 280 41 
Total Downstream 6,269 4,910   1,002 959 280 
       
Chemicals
      
Chevron Phillips Chemical Company LLC 1,896 1,747   334 24 2  1,908 1,896   449 334 24 
Other 19 20   2 1 4  20 19   3 2 1 
       
Total Chemicals 1,915 1,767   336 25 6  1,928 1,915   452 336 25 
       
All Other
      
Dynegy Inc. 525 698   86  (56)  (679) 682 525   189 86  (56)
Other 601 761   5  (31) 1  740 601   45 5  (31)
       
Total equity method $13,853 $11,811   $2,582 $1,029 $(25) $16,494 $13,853   $3,731 $2,582 $1,029 
Other at or below cost 536 508    563 536   
     
Total investments and advances $14,389 $12,319    $17,057 $14,389   
       
Total U.S. $3,788 $3,905   $588 $175 $(559)
Total United States $4,624 $3,788   $833 $588 $175 
Total International $10,601 $8,414   $1,994 $854 $534  $12,433 $10,601   $2,898 $1,994 $854 
      

     Descriptions of major affiliates are as follows:

Tengizchevroil ChevronTexacoChevron has a 50 percent equity ownership interest in TCO,Tengizchevroil (TCO), a joint venture formed in 1993 to develop the Tengiz and Korolev crude oil fields in Kazakhstan over a 40-year period.
      In 2004, as part of the funding of the expansion of TCO’s production facilities, ChevronTexaco purchased from TCO $2,200 of 6.124
Hamaca Chevron has a 30 percent Series B Notes, due 2014, guaranteed by TCO. Interest on the notes is payable semiannually and principal is to be repaid semiannually in equal installments beginning in February 2008. Immediately following the purchase of the Series B Notes, ChevronTexaco received from TCO approximately $1,800 representing a repayment of subordinated loans from the company, interest and dividends. The $2,200 investment in the Series B Notes, which the company intends to hold to their



FS-39

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
4NOTE 14.INVESTMENTS AND ADVANCES – Continued
maturity,Hamaca heavy oil production and the $1,800 distribution were recorded to “Investments and Advances.”upgrading project located in Venezuela’s Orinoco Belt.
 
LG-Caltex OilGS Caltex Corporation ChevronTexacoChevron owns 50 percent of LG-Caltex,GS Caltex (formerly LG Caltex Oil Corporation), a joint venture with GS Holdings. The joint venture, originally formed in 1967 between the LG Group and Caltex, to engage in importing, refiningimports, refines and marketing ofmarkets petroleum products and petrochemicals in South Korea.
 
Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, which provides the critical export route for crude oil both from TCO and Karachaganak.



FS-44

NOTE 13.INVESTMENTS AND ADVANCES — Continued
Star Petroleum Refining Company Ltd. ChevronTexacoChevron 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. ChevronTexacoChevron has a 50 percent equity ownership interest in Caltex Australia Limited (CAL). The remaining 50 percent of CAL is publicly owned. During 2002, the company wrote down its investment in CAL by $136 to its estimated fair value at September 30, 2002. At December 31, 2004,2005, the fair value of ChevronTexaco’sChevron’s share of CAL common stock was $1,130.approximately $1,900. The aggregate carrying value of the company’s investment in CAL was approximately $80$70 lower than the amount of underlying equity in CAL net assets.
 
Colonial Pipeline CompanyChevron owns an approximate 23 percent equity interest as a result of the Unocal acquisition. The Colonial Pipeline system runs from Texas to New Jersey and transports petroleum products in a 13-state market.
Chevron Phillips Chemical Company LLC ChevronTexacoChevron owns 50 percent of CPChem, formed in 2000 when Chevron merged most of its petrochemicals businesses with those of Phillips Petroleum Company.Company (now ConocoPhillips Corporation). At December 31, 2004,2005, the company’s carrying value of its investment in CPChem was approximately $130$100 lower than the amount of underlying equity in CPChem’s net assets.
 
Dynegy Inc. ChevronTexacoChevron owns an approximate 2524 percent equity interest in the common stock of Dynegy, an energya provider engaged in power generation,of electricity to markets and customers throughout the gathering and processing
of natural gas, and the fractionation, storage, transportation and marketing of natural gas liquids.United States. The company also holds investments in Dynegy preferred stock.
     Investment in Dynegy Common Stock At December 31, 2004,2005, the carrying value of the company’s investment in Dynegy common stock was approximately $150.$300. This amount was about $365$200 below the company’s proportionate interest in Dynegy’s underlying net assets. This difference is primarily the result of write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value that were deemed to be other than temporary. This difference has been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors contributing to the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly when appropriate to reflect the difference between these allocated values and Dynegy’s historical book values. The market value of the company’s investment in Dynegy’s common stock at December 31, 2004,2005, was approximately $450.$470.
     InvestmentsInvestment in Dynegy Notes and Preferred Stock Refer to Note 87, beginning on page FS-35FS-39, for a discussion of these investments.this investment.
 
Other Information“Sales “Sales and other operating revenues” on the Consolidated Statement of Income includes $8,824, $7,933 $6,308 and $6,522$6,308 with affiliated companies for 2005, 2004 2003 and 2002,2003, respectively. “Purchased crude oil and products” includes $3,219, $2,548 $1,740 and $1,839$1,740 with affiliated companies for 2005, 2004 2003 and 2002,2003, respectively.
     “Accounts and notes receivable” on the Consolidated Balance Sheet includes $1,188$1,729 and $827$1,188 due from affiliated companies at December 31, 20042005 and 2003,2004, respectively. “Accounts payable” includes $192$249 and $118$192 due to affiliated companies at December 31, 20042005 and 2003,2004, respectively.
     The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as ChevronTexaco’sChevron’s total share.


                          
  Affiliates   ChevronTexaco Share* 
Year ended December 31 2004  2003  2002   2004  2003  2002 
    
Total revenues $55,152  $42,323  $31,877   $25,916  $19,467  $15,049 
Income (loss) before income tax expense  5,309   1,657   (1,517)   3,015   1,211   70 
Net income (loss)  4,441   1,508   (1,540)   2,582   1,029   (25)
    
At December 31
                         
    
Current assets $16,506  $12,204  $16,808   $7,540  $5,180  $6,270 
Noncurrent assets  38,104   39,422   40,884    15,567   15,765   15,219 
Current liabilities  10,949   9,642   14,414    4,962   4,132   5,158 
Noncurrent liabilities  22,261   22,738   24,129    4,520   5,002   5,668 
    
Net equity
 $21,400  $19,246  $19,149   $13,625  $11,811  $10,663 
    
*The company’s share of income and underlying equity in the net assets of its investments includes the effects of write-downs of certain investments, largely related to Dynegy Inc. and Caltex Australia Ltd., as described in the preceding section.
                          
  Affiliates   Chevron Share 
Year ended December 31 2005  2004  2003   2005  2004  2003 
    
Total revenues $64,642  $55,152  $42,323   $31,252  $25,916  $19,467 
Income before income tax expense  7,883   5,309   1,657    4,165   3,015   1,211 
Net income  6,645   4,441   1,508    3,534   2,582   1,029 
    
At December 31
                         
    
Current assets $19,903  $16,506  $12,204   $8,537  $7,540  $5,180 
Noncurrent assets  46,925   38,104   39,422    17,747   15,567   15,765 
Current liabilities  13,427   10,949   9,642    6,034   4,962   4,132 
Noncurrent liabilities  26,579   22,261   22,738    4,906   4,520   5,002 
    
Net equity
 $26,822  $21,400  $19,246   $15,344  $13,625  $11,811 
    

FS-40FS-45

4NOTE 15.Notes to the Consolidated Financial StatementsPROPERTIES, PLANT AND EQUIPMENT


Millions of dollars, except per-share amounts

NOTE 15.14.
PROPERTIES, PLANT AND EQUIPMENT11,2

                                                    
  At December 31   Year ended December 31 
  Gross Investment at Cost   Net Investment2   Additions at Cost3   Depreciation Expense4,5 
  2004  2003  2002   2004  2003  2002   2004  2003  2002   2004  2003  2002 
          
Exploration and Production
                                                   
United States $37,329  $34,798  $39,986   $10,047  $9,953  $10,457   $1,584  $1,776  $1,658   $1,508  $1,815  $1,806 
International  38,721   37,402   36,382    21,192   20,572   18,908    3,090   3,246   3,343    2,180   2,227   2,132 
          
Total Exploration and Production  76,050   72,200   76,368    31,239   30,525   29,365    4,674   5,022   5,001    3,688   4,042   3,938 
          
Refining, Marketing and Transportation
                                                   
United States  12,826   12,959   13,423    5,611   5,881   6,296    482   389   671    490   493   570 
International  10,843   11,174   11,194    5,443   5,944   6,310    441   388   411    572   655   530 
          
Total Refining, Marketing and Transportation  23,669   24,133   24,617    11,054   11,825   12,606    923   777   1,082    1,062   1,148   1,100 
          
Chemicals
                                                   
United States  615   613   614    292   303   317    12   12   16    20   21   21 
International  725   719   731    392   404   420    27   24   37    26   38   21 
          
Total Chemicals  1,340   1,332   1,345    684   707   737    39   36   53    46   59   42 
          
All Other6
                                                   
United States  2,877   2,772   2,783    1,466   1,393   1,334    314   169   230    158   109   149 
International  18   119   118    15   88   113    2   8   55    3   26   2 
          
Total All Other  2,895   2,891   2,901    1,481   1,481   1,447    316   177   285    161   135   151 
          
Total United States  53,647   51,142   56,806    17,416   17,530   18,404    2,392   2,346   2,575    2,176   2,438   2,546 
Total International  50,307   49,414   48,425    27,042   27,008   25,751    3,560   3,666   3,846    2,781   2,946   2,685 
          
Total $103,954  $100,556  $105,231   $44,458  $44,538  $44,155   $5,952  $6,012  $6,421   $4,957  $5,384  $5,231 
          


                                                    
  At December 31   Year ended December 31 
  Gross Investment at Cost   Net Investment   Additions at Cost3  Depreciation Expense4,5
  2005  2004  2003   2005  2004  2003   2005  2004  2003   2005  2004  2003 
          
Upstream
                                                   
United States $43,390  $37,329  $34,798   $15,327  $10,047  $9,953   $2,160  $1,584  $1,776   $1,869  $1,508  $1,815 
International  54,497   38,721   37,402    34,311   21,192   20,572    4,897   3,090   3,246    2,804   2,180   2,227 
          
Total Upstream  97,887   76,050   72,200    49,638   31,239   30,525    7,057   4,674   5,022    4,673   3,688   4,042 
          
Downstream
                                                   
United States  13,832   12,826   12,959    6,169   5,611   5,881    793   482   389    461   490   493 
International  11,235   10,843   11,174    5,529   5,443   5,944    453   441   388    550   572   655 
          
Total Downstream  25,067   23,669   24,133    11,698   11,054   11,825    1,246   923   777    1,011   1,062   1,148 
          
Chemicals
                                                   
United States  624   615   613    282   292   303    12   12   12    19   20   21 
International  721   725   719    402   392   404    43   27   24    23   26   38 
          
Total Chemicals  1,345   1,340   1,332    684   684   707    55   39   36    42   46   59 
          
All Other6
                                                   
United States  3,127   2,877   2,772    1,655   1,466   1,393    199   314   169    186   158   109 
International  20   18   119    15   15   88    4   2   8    1   3   26 
          
Total All Other  3,147   2,895   2,891    1,670   1,481   1,481    203   316   177    187   161   135 
          
Total United States  60,973   53,647   51,142    23,433   17,416   17,530    3,164   2,392   2,346    2,535   2,176   2,438 
Total International  66,473   50,307   49,414    40,257   27,042   27,008    5,397   3,560   3,666    3,378   2,781   2,946 
          
Total $127,446  $103,954  $100,556   $63,690  $44,458  $44,538   $8,561  $5,952  $6,012   $5,913  $4,957  $5,384 
          
  
1
Refer to Note 2524, beginning on page FS-53FS-59, 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
Net2005 balances include assets acquired in connection with the acquisition of accumulated abandonment and restoration costs of $2,263 at December 31, 2002.Unocal Corporation. Refer to Note 2, beginning on page FS-36, for additional information.
  
3
Net of dry hole expense related to prior years’ expenditures of $28, $58 and $124 in 2005, 2004 and $36 in 2004, 2003, and 2002, respectively.
  
4
Depreciation expense includes accretion expense of $187, $93 and $132 in 2005, 2004 and 2003, respectively.
  
5
Depreciation expense includes discontinued operations of $22 $58 and $62$58 in 2004 2003 and 2002,2003, respectively.
  
6
Primarily mining operations of coal and other minerals, power generation businesses, real estate assets and management information systems.

NOTE 16.15.
ACCOUNTING FOR BUY/SELL CONTRACTS
In January and Februarythe first quarter 2005, the SECSecurities and Exchange Commission (SEC) issued comment letters to ChevronTexacoChevron and other companies in the oil and gas industry requesting disclosure of information related to the accounting for buy/sell contracts. Under a buy/sell contract, a company agrees to buy a specific quantity and quality of a commodity to be delivered at a specific location while simultaneously agreeing to sell a specified quantity and quality of a commodity at a different location to the same counterparty. Physical delivery occurs for each side of the transaction, and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and risk of nonperformance by the counterparty. Both parties settle each side of the buy/sell through separate invoicing.
     The company routinely hasenters into buy/sell contracts, primarily in the United States downstream business, associated with crude oil and refined products. For crude oil, these contracts are used to facilitate the company’s crude oil marketing activity, which includes the purchase and sale of crude oil production, fulfillment of the company’s supply arrangements as to physical delivery location and crude oil specifications, and purchase of crude oil to supply the company’s refining

system. For refined products,

buy/sell arrangements are used to help fulfill the company’s supply agreements to customer locations and specifications.
     The company accountshas historically accounted for buy/sell transactions in the Consolidated Statement of Income the same as any otherfor a monetary transaction for which title passes,— purchases are reported as “Purchased crude oil and products”; sales are reported as “Sales and other operating revenues.” The SEC raised the risks and rewards of ownership are assumed by the counterparties. At issue with the SEC isas to whether the industry’s accounting for buy/sell contracts instead should be shown net on the income statement and accounted for under the provisions of Accounting Principles Board (APB) Opinion No. 29,“Accounting for Nonmonetary Transactions”(APB 29). The company understands that others in the oil and gas industry may report buy/sell transactions on a net basis in the income statement rather than gross.
     The topic is under deliberation by the Emerging Issues Task Force (EITF) of the FASB deliberated this topic as Issue No. 04-13,“Accounting for Purchases and Sales of Inventory with the Same Counterparty.”TheAt its September 2005 meeting, the EITF first discussed this issue in November 2004. Additional research is being performedreached consensus that two or more legally separate exchange transactions with the same counterparty, including buy/sell transactions, should be combined and considered as a single arrangement for purposes of applying APB 29 when the transactions were entered into “in contemplation” of one another. EITF 04-13 was ratified by the FASB staff,in September 2005 and is effective


FS-46

NOTE 15.ACCOUNTING FOR
BUY/SELL CONTRACTS – Continued
for new arrangements, or modifications or renewals of existing arrangements, entered into beginning on or after April 1, 2006, which will be the effective date for the company’s adoption of this standard. Upon adoption, the company will report the net effect of buy/sell transactions on its Consolidated Statement of Income as “Purchased crude oil and products” instead of reporting the revenues associated with these arrangements as “Sales and other operating revenues” and the topic will be discussed again at a future EITF meeting. costs as “Purchased crude oil and products.”
While this issue iswas under deliberation by the EITF, the SEC staff directed ChevronTexacoChevron and other companies in its January and February 2005 comment letters to disclose on the face of the income statement the amounts associated with buy/sell contracts and to discuss in a footnote to the financial statements the basis for the underlying accounting.
     With regard to the latter, the company’s accounting treatment The amounts for buy/sell contracts is based on the view that such


FS-41

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
4NOTE 16.ACCOUNTING FOR BUY/SELL CONTRACTS – Continued
transactions are monetary in nature. Monetary transactions are outside the scope of APB 29. The company believes its accounting is also supported by the indicators of gross reporting of purchases and sales in paragraph 3 of EITF Issue No. 99-19,“Reporting Revenue Gross as a Principal versus Net as an Agent.”Additionally, FASB Interpretation No. 39,“Offsetting of Amounts Related to Certain Contracts”(FIN 39), prohibits a receivable from being netted against a payable when the receivable is subject to credit risk unless a right of offset exists that is enforceable by law. The company also views netting the separate components of buy/sell contracts in the income statement to be inconsistent with the gross presentation that FIN 39 requires for the resulting receivable and payable on the balance sheet.
      The company’s buy/sell transactions are also similar to the “barrel back” example used in other accounting literature, including EITF Issue No. 03-11,“Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3”(which indicates a company’s decision to show buy/sell-types of transactions gross on the income statement as being a matter of judgment of the relevant facts and circumstances of the company’s activities) and Derivatives Implementation Group (DIG) Issue No. K1,“Miscellaneous: Determining Whether Separate Transactions Should be Viewed as a Unit.”
     The company further notes that the accounting for buy/sell contracts as separate purchases and sales is in contrast to the accounting for other types of contracts typically described by the industry as exchange contracts, which are considered non-monetary in nature and appropriately shown net on the income statement. Under an exchange contract, for example, one company agrees to exchange refined products in one location for another company’s same quantity of refined products in another location. Upon transfer, the only amounts that may be invoiced are for transportation and quality differentials. Among other things, unlike buy/sell contracts, the obligations of each party to perform under the contract are not independent and the risks and rewards of ownership are not separately transferred.
     As shown on the company’s Consolidated Statement of Income “Sales and other operating revenues” for the three years ending December 31, 2004, included2005, were $23,822, $18,650 and $14,246, and $7,963, respectively, forrespectively. These revenue amounts associated with buy/sell contracts.contracts represented 12 percent of total “Sales and other operating revenues” in 2005, 2004 and 2003. Nearly all of these revenue amounts in each period associated with buy/sell contracts pertain to the company’s downstream segment. The costs associated with these buy/sell revenue amounts are included in “Purchased crude oil and products” on the Consolidated Statement of Income in each period.

NOTE 17.16.
TAXES
                    
 Year ended December 31  Year ended December 31 
 2004 2003 2002  2005 2004 2003 
       
Taxes on income1
      
U.S. federal      
Current $2,246   $1,133 $(80) $1,459   $2,246 $1,133 
Deferred2
  (290)  121  (414) 567    (290) 121 
State and local 345   133 21  409   345 133 
       
Total United States 2,301   1,387  (473) 2,435   2,301 1,387 
       
International            
Current 5,150   3,864 3,138  7,837   5,150 3,864 
Deferred2
 66   43 333  826   66 43 
       
Total International 5,216   3,907 3,471  8,663   5,216 3,907 
       
Total taxes on income $7,517   $5,294 $2,998  $11,098   $7,517 $5,294 
      
  
1
Excludes income tax expense of $100 $50 and $26$50 related to discontinued operations for 2004 2003 and 2002,2003, respectively.
  
2
Excludes a U.S. deferred tax benefit of $191 and a foreign deferred tax expense of $170 associated with the adoption of FAS 143 in 2003 and the related cumulative effect of changes in accounting method in 2003.
      
     In 2004,2005, the before-tax income for U.S. operations, including related corporate and other charges, was $7,776,$6,733, compared with a before-tax income of $7,776 and $5,664 in 2004 and 2003, and a before-tax loss of $2,162 in 2002.respectively. For international operations, before-tax income was $18,464, $12,775 and $7,012 in 2005, 2004 and $6,262 in 2004, 2003, and 2002, respectively. U.S. federal income tax

expense was reduced by $289, $176 and $196 in 2005, 2004 and $208 in 2004, 2003, and 2002, respectively, for business tax credits.
     The company’s effective income tax rate varied fromreconciliation between the U.S. statutory federal income tax rate because ofand the following:company’s effective income tax rate is explained in the table below:
                    
 Year ended December 31  Year ended December 31 
 2004 2003 2002  2005 2004 2003 
       
U.S. statutory federal income tax rate  35.0%   35.0%  35.0%  35.0%   35.0%  35.0%
Effect of income taxes from international operations in excess of taxes at the U.S. statutory rate 5.3   12.8 29.9  9.2   5.3 12.8 
State and local taxes on income, net of U.S. federal income tax benefit 0.9   0.5 1.1  1.0   0.9 0.5 
Prior-year tax adjustments  (1.0)   (1.6)  (7.1) 0.1    (1.0)  (1.6)
Tax credits  (0.9)   (1.5)  (5.1)  (1.1)   (0.9)  (1.5)
Effects of enacted changes in tax laws  (0.6)  0.3 2.0  –    (0.6) 0.3 
Impairment of investments in equity affiliates –   – 12.6 
Capital loss tax benefit  (2.1)   (0.8) –   (0.1)   (2.1)  (0.8)
Other –    (1.9) –  0.2   –  (1.9)
       
Consolidated companies 36.6   42.8 68.4  44.3   36.6 42.8 
Effect of recording income from certain equity affiliates on an after-tax basis –    (1.0) 4.7 
   
Effect of recording income from equity affiliates on an after-tax basis  (0.2)  –  (1.0)
Effective tax rate  36.6%   41.8%  73.1%  44.1%   36.6%  41.8%
      
      
     International taxes in 2004 were reduced by approximately $129 related to changes in income tax laws.     The company records its deferred taxes on a tax-jurisdiction basis and classifies those net amounts as current or noncurrent based on the balance sheet classification of the related assets or liabilities.



FS-42

4NOTE 17.TAXES – Continued
     The reported deferred tax balances are composed of the following:
            
 At December 31  At December 31 
 2004 2003*  2005 2004 
       
Deferred tax liabilities      
Properties, plant and equipment $8,889   $8,539  $14,220   $8,889 
Investments and other 931   602  1,469   931 
       
Total deferred tax liabilities 9,820   9,141  15,689   9,820 
       
Deferred tax assets      
Abandonment/environmental reserves  (1,495)   (1,221)  (2,083)   (1,495)
Employee benefits  (965)   (1,272)  (1,250)   (965)
Tax loss carryforwards  (1,155)   (956)  (1,113)   (1,155)
Capital losses  (687)   (264)  (246)   (687)
Deferred credits  (838)   (578)  (1,618)   (838)
Foreign tax credits  (93)   (352)  (1,145)   (93)
Inventory  (99)   (57)  (182)   (99)
Other accrued liabilities  (300)   (199)  (240)   (300)
Miscellaneous  (876)   (935)  (1,237)   (876)
       
Total deferred tax assets  (6,508)   (5,834)  (9,114)   (6,508)
       
Deferred tax assets valuation allowance 1,661   1,553  3,249   1,661 
       
Total deferred taxes, net $4,973   $4,860  $9,824   $4,973 
      
     In 2005, the reported amount of net total deferred taxes increased by approximately $5,000 from the amount reported in 2004. The increase was largely attributable to net deferred taxes arising through the Unocal acquisition.
     Deferred tax assets related to foreign tax credits increased approximately $1,000 between 2004 and 2005. The associated valuation allowance also increased approximately the same amount. The change in both categories reflected the addition of Unocal amounts as well as the effect of the company’s tax election in 2005 for certain heritage-Chevron international upstream operations.


FS-47

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
  
*
2003 conformed to 2004 presentation.NOTE 16.TAXES — Continued
     
The overall valuation allowance relates to foreign tax credit carryforwards, tax loss carryforwards and temporary differences for which no benefit is expected to be realized. Tax loss carryforwards exist in many foreign jurisdictions. Whereas some of these tax loss carryforwardscarry forwards do not have an expiration date, others expire at various times from 20052006 through 2011.2013. Foreign tax credit carryforwards of $93$1,145 will expire in 2014.2015.
     At December 31, 20042005 and 2003,2004, deferred taxes were classified in the Consolidated Balance Sheet as follows:
            
 At December 31  At December 31 
 2004 2003  2005 2004 
       
Prepaid expenses and other current assets $(1,532)  $(940) $(892)  $(1,532)
Deferred charges and other assets  (769)   (641)  (547)   (769)
Federal and other taxes on income 6   24  1   6 
Noncurrent deferred income taxes 7,268   6,417  11,262   7,268 
       
Total deferred income taxes, net $4,973   $4,860  $9,824   $4,973 
      
      
     It is the company’s policy for subsidiaries that are included in the U.S. consolidated tax return to record income tax expense as though they file separately, with the parent recording the adjustment to income tax expense for the effects of consolidation.
     Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely.
Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $10,000$14,317 at December 31, 2004.2005. A significant majority of this amount represents earnings reinvested as part of the company’s ongoing international business. It is not practicable to estimate the amount of taxes that might be payable on the eventual remittance of such earnings. The company does not
anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.
      
American Jobs Creation Act of 2004 In October 2004, the American Jobs Creation Act of 2004 was passed into law. The Act provides a deduction for income from qualified domestic refining and upstream production activities, which will be phased in from 2005 through 2010. For that specific category of income, the company expects the net effect of this provision of the Act to result in a decrease in the federal effective tax rate for 2005 and 2006 to approximately 34 percent, based on current earnings levels. In the long term, the company expects that the new deduction will result in a decrease of the federalannual effective tax rate to about 32 percent for that category of income, based on current earnings levels.
     Under the guidance in FASB Staff Position No. FAS 109-1,“Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,”the tax deduction on qualified production activities provided by the American Jobs Creation Act of 2004 will be treated as a “special deduction,” as described in FAS 109. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the period in which the deduction is claimed on the company’s tax return.
     The Act also provides for a limited opportunity to repatriate earnings from outside the United States at a special reduced tax rate that can be as low as 5.25 percent. In early 2005, the company was in the process of reviewing the guidance that the IRS issued on January 13, 2005, regarding this provision and also considering other relevant information. The company does not anticipate a major change in its plans for repatriating earnings from international operations under the provisions of the Act.
     Taxes other than on income were as follows:
                    
 Year ended December 31  Year ended December 31 
 2004 2003 2002  2005 2004 2003 
       
United States      
Excise taxes on products and merchandise $4,147   $3,744 $3,990  $4,521   $4,147 $3,744 
Import duties and other levies 5   11 12  8   5 11 
Property and other miscellaneous taxes 359   309 348  392   359 309 
Payroll taxes 137   138 141  149   137 138 
Taxes on production 257   244 179  323   257 244 
       
Total United States 4,905   4,446 4,670  5,393   4,905 4,446 
       
International      
Excise taxes on products and merchandise 3,821   3,351 3,016  4,198   3,821 3,351 
Import duties and other levies 10,542   9,652 8,587  10,466   10,542 9,652 
Property and other miscellaneous taxes 415   320 291  535   415 320 
Payroll taxes 52   54 46  52   52 54 
Taxes on production 86   83 79  138   86 83 
       
Total International 14,916   13,460 12,019  15,389   14,916 13,460 
       
Total taxes other than on income* $19,821   $17,906 $16,689  $20,782   $19,821 $17,906 
      
  
*
Includes taxes on discontinued operations of $3 and $5 $7 in 2004 2003 and 2002,2003, respectively.


FS-43

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

NOTE 18.17.
SHORT-TERM DEBT
            
 At December 31  At December 31 
 2004 2003  2005 2004 
       
Commercial paper* $4,068   $4,078  $4,098   $4,068 
Notes payable to banks and others with originating terms of one year or less 310   190  170   310 
Current maturities of long-term debt 333   863  467   333 
Current maturities of long-term capital leases 55   71  70   55 
Redeemable long-term obligations   
Long-term debt 487   487 
Redeemable long-term obligations
Long-term debt		 487   487 
Capital leases 298   299  297   298 
       
Subtotal 5,551   5,988  5,589   5,551 
Reclassified to long-term debt  (4,735)   (4,285)  (4,850)   (4,735)
       
Total short-term debt $816   $1,703  $739   $816 
      
  
*Weighted-average interest rates at December 31, 2005 and 2004, and 2003, were 1.984.18 percent and 1.011.98 percent, respectively.
      
     Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.
     The company periodically enters into interest rate swaps on a portion of its short-term debt. See Note 87, beginning on page FS-35FS-39, for information concerning the company’s debt-related derivative activities.
     At December 31, 2004,2005, the company had $4,735$4,850 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 20042005 or at year-end.



FS-48

NOTE 17.SHORT-TERM DEBT — Continued
     At December 31, 20042005 and 2003,2004, the company classified $4,735$4,850 and $4,285,$4,735, respectively, of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital in 2005,2006, as the company has both the intent and the ability to refinance this debt on a long-term basis.

NOTE 19.18.
LONG-TERM DEBT
ChevronTexacoChevron has three “shelf” registrationsregistration statements on file with the SEC that together would permit the issuance of $3,800 of debt securities pursuant to Rule 415 of the Securities Act of 1933. Total long-term debt, excluding capital leases, at December 31, 2005, was $11,807, which included $1,861 assumed in connection with the acquisition of Unocal. The company’s long-term debt outstanding at year-end 20042005 and 20032004 was as follows:

            
 At December 31  At December 31 
 2004 2003  2005 2004 
       
3.5% notes due 2007 $1,995   $1,993  $1,992   $1,995 
3.375% notes due 2008 754   749  736   754 
5.5% note due 2009 422   431 
7.327% amortizing notes due 20141
 360   360 
7.5% debentures due 20291
 475   – 
5.05% debentures due 20121
 412   – 
5.5% notes due 2009 406   422 
7.35% debentures due 20091
 347   – 
7% debentures due 20281
 259   – 
9.75% debentures due 2020 250   250  250   250 
5.7% notes due 2008 206   220 
7.327% amortizing notes due 20142
 247   360 
Fixed interest rate notes, maturing from 2006 to 2015 (8.1%)1,3
 241   – 
8.625% debentures due 2031 199   199  199   199 
8.625% debentures due 2032 199   199  199   199 
7.5% debentures due 2043 198   198  198   198 
Fixed and floating interest rate loans due 2007 to 2009 (4.4%)1,3
 194   – 
9.125% debentures due 20061
 167   – 
8.625% debentures due 2010 150   150  150   150 
8.875% debentures due 2021 150   150  150   150 
8% debentures due 2032 148   148 
7.09% notes due 2007 144   150  144   144 
8.25% debentures due 2006 129   150  129   129 
6.625% notes due 2004 –   499 
8.11% amortizing notes due 20042
 –   240 
6.0% notes due 2005 –   299 
Medium-term notes, maturing from 2017 to 2043 (7.1%)3
 210   210 
Other foreign currency obligations (4.0%)3
 39   52 
Other long-term debt (4.3%)3
 410   730 
Medium-term notes, maturing from 2017 to 2043 (7.5%)3
 210   210 
Other foreign currency obligations (3.2%)3
 30   39 
5.7% notes due 2008 –   206 
Other long-term debt (6.4%)3
 141   262 
       
Total including debt due within one year 5,815   7,229  7,424   5,815 
Debt due within one year  (333)   (863)  (467)   (333)
Reclassified from short-term debt 4,735   4,285  4,850   4,735 
       
Total long-term debt $10,217   $10,651  $11,807   $10,217 
      
  
1
Debt assumed with acquisition of Unocal in 2005.
2
Guarantee of ESOP debt.
  
2
Debt assumed from ESOP in 1999.
3
Less than $150$100 individually; weighted-average interest ratesrate at December 31, 2004.2005.
      
     Consolidated long-term debt maturing after December 31, 2004,2005, is as follows: 2005 – $333; 2006 – $149;$467; 2007 – $2,178;$2,287; 2008 – $1,061; and$856; 2009 – $455;$782; and 2010 – $176; after 20092010 – $1,639.$2,856.

     In 2004,October 2005, the company repaid $500fully redeemed Pure Resources 7.125 percent Senior Notes due 2011 for $395. The company’s $150 of 6.625Texaco Brasil zero coupon notes were paid at maturity in November 2005. In December 2005, the company exercised a par call redemption of $200 for Texaco Capital Inc. 5.7 percent notes and $240 of 8.11 percent notes that matured during the year. Other repayments during 2004 include $300 of 6 percent notesNotes due June 2005 and $265 in various Philippine debt.2008.
     In January 2005, the company contributed $98 to permit the ESOP to make a principal payment of $113.

NOTE 20.19.
NEW ACCOUNTING STANDARDS
FASB Interpretation No. 46, “Consolidation of Variable Interest Entities”(FIN 46) FIN 46 was issued in January 2003 and established standards for determining under what circumstances a variable interest entity (VIE) should be consolidated by its primary beneficiary. FIN 46 also requires disclosures about VIEs that the company is not required to consolidate but in which it has a significant variable interest. In December 2003, the FASB issued FIN 46-R, which not only included amendments to FIN 46, but also required application of the interpretation to all affected entities no later than March 31, 2004, for calendar year- reporting companies. Prior to this requirement, companies were required to apply the interpretation to special-purpose entities by December 31, 2003. The full adoption of the interpretation as of March 31, 2004, including the requirement relating to special-purpose entities, did not have an impact on the company’s results of operations, financial position or liquidity.
FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”(FSP FAS 106-2). In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became law. The Act



FS-44

4NOTE 20.NEW ACCOUNTING STANDARDS – Continued
introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB issued FSP FAS 106-2. One U.S. subsidiary was deemed at least actuarially equivalent and eligible for the federal subsidy. The effect on the company’s postretirement benefit obligation and the associated annual expense wasde minimis.
FASB Statement No. 151, “Inventory Costs, an Amendment of ARB No. 43, Chapter 4” (FAS 151)(FAS 151) In November 2004, the FASB issued FAS 151, which isbecame effective for the company on January 1, 2006. The standard amends the guidance in Accounting Research Bulletin (ARB) No. 43, Chapter 4,“Inventory Pricing,”to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and spoilage. In addition, the standard requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The company is currently evaluating the impactadoption of this standard.
FASB Statement No. 123R, “Share-Based Payment”(FAS 123R) In December 2004, the FASB issued FAS 123R, which requires that compensation costs relating to share-based payments be recognized in the company’s financial statements. The company currently accounts for those payments under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25,“Accounting for Stock Issued to Employees,”and related interpretations. The company is preparing to implement this standard effective July 1, 2005. Although the transition method to be used to adopt the standard haswill not been selected, the impact of adoption is expected to have a minimalan impact on the company’s results of operations, financial position andor liquidity. Refer to Note 1, beginning on page FS-30, for the company’s calculation of the pro forma impact on net income of FAS 123, which would be similar to that under FAS 123R.
 
FASB StatementEITF Issue No. 153, “Exchanges of Nonmonetary Assets, – an Amendment of APB Opinion No. 29,”04-6, “Accounting for Stripping Costs Incurred During Production in the Mining Industry” (Issue 04-6) (FAS 153) In December 2004,March 2005, the FASB issued FAS 153,ratified the earlier EITF consensus on Issue 04-6, which is effective for the company on January 1, 2006. Stripping costs are costs of removing overburden and other waste materials to access mineral deposits. The consensus calls for asset-exchange transactions beginning July 1, 2005. Under APB 29, assets received in certain types of nonmonetary exchanges were permittedstripping costs incurred once a mine goes into production to be recorded attreated as variable production costs that should be considered a component of mineral inventory cost subject to ARB No. 43,“Restatement and Revision of Accounting Research Bulletins.”Adoption of this accounting for its coal, oil sands and other mining operations will not have a significant effect on the carrying valuecompany’s results of the assets that were exchanged (i.e., recorded on a carryover basis). As amended by FAS 153, assets received in some circumstances will have to be recorded instead at their fair values. In the past, ChevronTexaco has not engaged in a large number of nonmon-etary asset exchanges for significant amounts.operations, financial position or liquidity.

NOTE 21.20.
ACCOUNTING FOR SUSPENDED EXPLORATORY WELLS
Refer to Note 1, beginning on page FS-30FS-34, in the section “Properties, Plant and Equipment” for a discussion of the company’s accounting policy for the cost of exploratory wells. The company’s suspended wells are reviewed in this context on a quarterly basis.
     The SEC issued comment letters during 2004 and in February 2005 to a number of companies in the oil and gas industry related to the accounting for suspended exploratory wells, particularly for those suspended under certain circumstances for more

than one year. In FebruaryApril 2005, the FASB issued a proposed FSP to amendFASB Staff Position (FSP) FAS 19-1,“Accounting for Suspended Well Costs,”which amended FAS 19,“Financial Accounting and Reporting by Oil and Gas Producing Companies.”The company elected early application of this guidance with the first quarter 2005 financial statements.
Under the provisions of the draft FSP FAS 19-1, exploratory well costs would continue to be capitalized after the completion of drilling when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project.



FS-49

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
NOTE 20.ACCOUNTING FOR SUSPENDED
EXPLORATORY WELLS – Continued
If either condition is not met, or if an enterprise obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. The FSP providedprovides a number of indicators needing to be presentthat can assist an entity to demonstrate sufficient progress wasis being made in assessing the reserves and economic viability of the project.
     The company will monitor the continuing deliberations of the FASB on this matter and the possible implications, if any, to the company’s accounting policy and the amounts capitalized for suspended-well costs. The disclosures and discussion below address those suggested in the draft FSP and in the additional guidance issued by the SEC in its February 2005 comment letter to companies in the oil and gas industry.
     The following table indicates the changes to the company’s suspended exploratory-well costs for the three years ended December 31, 2004:2005. No capitalized exploratory well costs were charged to expense upon the adoption of FSP FAS 19-1. Amounts may differ from those previously disclosed due to the requirements of FSP FAS 19-1 to exclude costs suspended and expensed in the same annual period.
                    
 Year ended December 31  Year ended December 31 
 2004 2003 2002  2005 2004 2003 
       
Beginning balance at January 1 $549   $478 $655  $671   $549 $478 
Additions associated with the acquisition of Unocal 317   – – 
Additions to capitalized exploratory well costs pending the determination of proved reserves 262   346 209  290   252 344 
Reclassifications to wells, facilities and equipment based on the determination of proved reserves  (64)   (145)  (310)  (140)   (64)  (145)
Capitalized exploratory well costs charged to expense  (76)   (128)  (46)  (6)   (66)  (126)
Other reductions* –    (2)  (30)  (23)  –  (2)
       
Ending balance at December 31 $671   $549 $478  $1,109   $671 $549 
      
  
*Represents aRepresent property sale in 2003sales and a retirement due to a legal settlement in 2002.an exchange.
      
     The following table provides an aging of capitalized well costs based on the date the drilling was completed, and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:drilling. The aging of the former Unocal wells is based on the date the drilling was completed, rather than Chevron’s August 2005 acquisition of Unocal.
                    
 Year ended December 31  Year ended December 31 
 2004   2003 2002  2005 2004 2003 
       
Exploratory well costs capitalized for a period of one year or less $222   $181 $170  $259   $222 $181 
Exploratory well costs capitalized for a period greater than one year 449   368 308  850   449 368 
       
Balance at December 31 $671   $549 $478  $1,109   $671 $549 
       
Number of projects with exploratory well costs that have been capitalized for a period greater than one year* 22   22 27  40   22 22 
      
  
*Certain projects have multiple wells or fields or both.
      
     Of the $671$850 of suspendedexploratory well costs capitalized for a period greater than one year at December 31, 2004,2005, approximately $290$313 (20 projects) related to 30 wellsprojects that had drilling activities under way or firmly planned for the near future. An additional $63 (four projects) had drilling activity dur-
ing 2005. The $474 balance related to 16 projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not under way or firmly planned


FS-45

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
4NOTE 21.ACCOUNTING FOR EXPLORATORY WELLS – Continued
for the near futurefuture. Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development.
     The balance related to wells in areas for which drilling was under way or firmly plannedprojects for the near future.
     Of$474 referenced above had the $290, approximately $50 related to the well costs suspended one year or less since drilling was completed, and $240 related to costs suspended for more than one year since the completion of drilling. Of the $240 for 11 projects suspended for more than one year since the completion of drilling,following activities associated with assessing the reserves and the projects’ economic viability included:viability: (a) $75 – discussions of joint development$141 — additional seismic interpretation planned, with an operator in an adjacent field and selection of subsurface and development plans, with front-end-engineeringfront-end engineering and design (FEED) expected to begincommence in 20052007 (two projects); (b) $82 — evaluation of drilling results and pre-FEED studies on-going with FEED expected to commence in 2006 (one project); (b)(c) $74 — finalization of pre-unit agreement with operator of adjacent field and the progression of joint subsurface and joint concept selection studies, with FEED expected to begin in 2006 (one project); (d) $63 – negotiations with contractors for— FEED contracts executed in 2005 and negotiations with potential customers forcontinued marketing of equity natural gas (two projects); (c) $42 – award of contracts for FEED and finalization of fiscal issues with the host country (one project); (d) $20 - - finalization of commercial terms with partners with award of detailed engineering and design contracts expected by the end of 2005 (one project); and (e) $40 –$114 — miscellaneous activities for 10 projects with smaller amounts suspended. Progress isWhile progress was being made on all the projects in this category; andcategory, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations connected with the projects.
     Included The majority of these decisions are expected to occur in the $449 in the table on the preceding page for year-end 2004next three years.
     The $850 of suspended well costs were $42capitalized for four projects and $50 fora period greater than one project that related to costs suspended in 2000 and 1998, respectively, when drilling in the associated project areas was completed. Certain wells in the project areas may have been suspended prior to these years of last drilling. Other well costs in the $449 total were associated with projects for which drilling was completed since 2000.
     If an FSP is implemented similar to the draft issued in February 2005, the company does not believe it would result in
the immediate expensing of a significant amount of suspended-well costs. However, the SEC staff has indicated that it generally would not view conducting environmental and engineering design studies as reasonable support for the suspending of costs beyond one year after drilling is complete. If such restrictions are included in the final FSP, the company may be required to expense a significant amount for wells that had found sufficient hydrocarbons to justify their completion as producing wells and for projects the company continued to consider economically and operationally viable. If a final rule required the company to expense the entire $240 before-tax carrying value for the 11 projects referenced above that were suspended as of December 31, 2004, for more2005, represents 105 exploratory wells in 40 projects. The tables below contain the aging of these costs on a well and project basis:
     Exploratory wells costs greater than one year after the completion of drilling, the after-tax charge to earnings would be $150.year:
         
      Number 
Aging based on drilling completion date of individual wells: Amount  of wells 
 
1994–2000 $147   28 
2001–2004  703   77 
 
Total $850   105 
 
         
      Number 
Aging based on drilling completion date of last well in project: Amount  of projects 
 
1998–2000 $91   4 
2001–2005  759   36 
 
Total $850   40 
 

NOTE 22.21.
EMPLOYEE BENEFIT PLANS
The company has defined-benefit pension plans for many employees. The company typically funds only thosepre-funds defined-benefit plans for which funding isas required under laws and regulations.by local regulations or in certain situations where pre-funding provides economic advantages. In the United States, this includes all qualified tax-exempt plans are subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company typically does not typically fund domestic nonqualified tax-exempt pension plans that are not subject to funding requirements under laws and regulations because contributions to these pension plans may be



FS-50

NOTE 21.EMPLOYEE BENEFIT PLANS — Continued
less economic and investment returns may be less attractive than the company’s other investment alternatives.
     The company also sponsors other postretirement plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees.
The plans are unfunded, and the company and the retirees share the costs. In June 2004,For retiree medical coverage in the company’s main U.S. plan, the increase to the company announced changescontributions for retiree medical coverage is limited to its primary U.S. postretirement benefit plan, which include a limit on future increasesno more than 4 percent each year, effective at retirement, beginning in the company contribution, an increase in service points (combination of age and years of company service) required to receive full coverage, and the plan’s prescription drug coverage for retirees becoming secondary to Medicare Part D. Life2005. Certain life insurance benefits are paid by the company and annual contributions are based on actual plan experience.
     The company uses a measurement date of December 31 to value its pension and other postretirement benefit plan obligations.



FS-46

4NOTE 22.EMPLOYEE BENEFIT PLANS – Continued
The status of the company’s pension and other postretirement benefit plans for 20042005 and 20032004 is as follows:
                                        
 Pension Benefits     Pension Benefits    
 2004 2003  Other Benefits  2005 2004  Other Benefits 
 U.S. Int'l. U.S. Int'l. 2004 2003  U.S. Int'l. U.S. Int'l. 2005 2004 
                 
CHANGE IN BENEFIT OBLIGATION
          
Benefit obligation at January 1 $5,819 $2,708   $5,308 $2,163 $3,135   $2,865  $6,587 $3,144   $5,819 $2,708 $2,820   $3,135 
Assumption of Unocal benefit obligations 1,437 169   – – 277   – 
Service cost 170 70   144 54 26   28  208 84   170 70 30   26 
Interest cost 326 180   334 151 164   191  395 199   326 180 164   164 
Plan participants’ contributions 1 6   1 1 –   –  1 6   1 6 –   – 
Plan amendments – 26   – 25  (811)  –  42 7   – 26 –    (811)
Actuarial loss1
 861 165   708 223 497   244 
Actuarial loss 593 476   861 165 189   497 
Foreign currency exchange rate changes – 207   – 257 8   7  –  (293)  – 207  (2)  8 
Benefits paid  (590)  (213)   (676)  (162)  (199)   (200)  (669)  (181)   (590)  (213)  (226)   (199)
Curtailment –  (6)  –  (4) –   –  – –   –  (6) –   – 
Special termination benefits – 1   – – –   –  – –   – 1 –   – 
                 
Benefit obligation at December 31 6,587 3,144   5,819 2,708 2,820   3,135  8,594 3,611   6,587 3,144 3,252   2,820 
                 
CHANGE IN PLAN ASSETS
          
Fair value of plan assets at January 1 4,444 2,129   3,190 1,645 –   –  5,776 2,634   4,444 2,129 –   – 
Acquisition of Unocal plan assets 1,034 65   – – –   – 
Actual return on plan assets 589 229   726 203 –   –  527 441   589 229 –   – 
Foreign currency exchange rate changes – 172   – 228 –   –  –  (303)  – 172 –   – 
Employer contributions 1,332 311   1,203 214 199   200  794 228   1,332 311 226   199 
Plan participants’ contributions 1 6   1 1 –   –  1 6   1 6 –   – 
Benefits paid  (590)  (213)   (676)  (162)  (199)   (200)  (669)  (181)   (590)  (213)  (226)   (199)
                 
Fair value of plan assets at December 31 5,776 2,634   4,444 2,129 –   –  7,463 2,890   5,776 2,634 –   – 
                 
FUNDED STATUS
  (811)  (510)   (1,375)  (579)  (2,820)   (3,135)  (1,131)  (721)   (811)  (510)  (3,252)   (2,820)
Unrecognized net actuarial loss1
 2,080 939   1,598 918 1,071   646 
Unrecognized net actuarial loss 2,332 1,108   2,080 939 1,167   1,071 
Unrecognized prior-service cost 308 104   350 92  (771)   (19) 305 89   308 104  (679)   (771)
Unrecognized net transitional assets – 7   – 8 –   –  – 5   – 7 –   – 
                 
Total recognized at December 31 $1,577 $540   $573 $439 $(2,520)  $(2,508) $1,506 $481   $1,577 $540 $(2,764)  $(2,520)
                 
AMOUNTS RECOGNIZED IN THE CONSOLIDATED BALANCE SHEET AT DECEMBER 31
          
Prepaid benefit cost $1,759 $933   $10 $679 $–   $–  $1,961 $960   $1,759 $933 $–   $– 
Accrued benefit liability2
  (712)  (458)   (970)  (392)  (2,520)   (2,508)
Accrued benefit liability1
  (890)  (545)   (712)  (458)  (2,764)   (2,520)
Intangible asset 14 5   349 18 –   –  12 2   14 5 –   – 
Accumulated other comprehensive income3
 516 60   1,184 134 –   – 
Accumulated other comprehensive income2
 423 64   516 60 –   – 
                 
Net amount recognized $1,577 $540   $573 $439 $(2,520)  $(2,508) $1,506 $481   $1,577 $540 $(2,764)  $(2,520)
            
  
1
Other benefits in 2003 include a $10 gain for the Medicare Part D federal subsidy for a small subsidiary plan.
2
The company recorded additional minimum liabilities of $530$435 and $64$66 in 20042005 for U.S. and international plans, respectively, and $1,533$530 and $152$64 in 20032004 for U.S. and international plans, respectively, to reflect the amount of unfunded accumulated benefit obligations. The long-term portion of accrued benefits liability is recorded in “Reserves for employee benefit plans,” and the short-term portion is reflected in “Accrued liabilities.”
  
32
“Accumulated other comprehensive income” includes deferred income taxes of $181$148 and $21$22 in 20042005 for U.S. and international plans, respectively, and $415$181 and $47$21 in 20032004 for U.S. and international plans, respectively. This item is presented net of these taxes in the Consolidated Statement of Stockholders’ Equity.

FS-51

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. and international pension plans were $ 6,117$7,931 and $3,080 respectively, at December 31, 2005, and $6,117 and $2,734, respectively, at December 31, 2004, and $5,374 and $2,372, respectively, at December 31, 2003.2004.
     Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 20042005 and 2003,2004 was:
            
 At December 31  At December 31 
 2004 2003  2005 2004 
       
Projected benefit obligations $1,449   $6,637  $2,950   $1,449 
Accumulated benefit obligations 1,360   6,067  2,625   1,360 
Fair value of plan assets 282   4,791  1,359   282 
      


FS-47

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
4NOTE 22.EMPLOYEE BENEFIT PLANS – Continued
 
The components of net periodic benefit cost for 2005, 2004 2003 and 20022003 were:
                                             
 Pension Benefits     Pension Benefits    
 2004 2003 2002  Other Benefits  2005 2004 2003  Other Benefits 
 U.S. Int’l. U.S. Int’l. U.S. Int’l. 2004 2003 2002  U.S. Int'l. U.S. Int'l. U.S. Int'l. 2005 2004 2003 
                 
Service cost $170 $70   $144 $54 $112 $47 $26   $28 $25  $208 $84   $170 $70 $144 $54 $30   $26 $28 
Interest cost 326 180   334 151 334 143 164   191 178  395 199   326 180 334 151 164   164 191 
Expected return on plan assets  (358)  (169)   (224)  (132)  (288)  (138) –   – –   (449)  (208)   (358)  (169)  (224)  (132) –   – – 
Amortization of transitional assets – 1   –  (3) –  (3) –   – –  – 2   – 1 –  (3) –   – – 
Amortization of prior-service costs 42 16   45 14 32 12  (47)   (3)  (3) 45 16   42 16 45 14  (91)   (47)  (3)
Recognized actuarial losses (gains) 114 69   133 42 32 27 54   12  (1)
Recognized actuarial losses 177 51   114 69 133 42 93   54 12 
Settlement losses 96 4   132 1 146 1 –   – –  86 –   96 4 132 1 –   – – 
Curtailment losses – 2   – 6 – – –   – –  – –   – 2 – 6 –   – – 
Special termination benefits recognition – 1   – – – – –   – –  – –   – 1 – – –   – – 
                 
Net periodic benefit cost $390 $174   $564 $133 $368 $89 $197   $228 $199  $462 $144   $390 $174 $564 $133 $196   $197 $228 
            
 
Assumptions The following weighted average assumptions were used to determine benefit obligations and net period benefit costs for years ended December 31:
                                       
  Pension Benefits    
  2004 2003 2002  Other Benefits 
  U.S.  Int’l.   U.S.  Int’l.  U.S.  Int’l.  2004   2003  2002 
         
Assumptions used to determine benefit obligations
Discount rate		  5.8%  6.4%   6.0%  6.8%  6.8%  7.1%  5.8%   6.1%  6.8%
Rate of compensation increase  4.0%  4.9%   4.0%  4.9%  4.0%  5.5%  4.1%   4.1%  4.1%
Assumptions used to determine net periodic benefit cost
Discount rate*		  5.9%  6.8%   6.3%  7.1%  7.4%  7.7%  6.1%   6.8%  7.3%
Expected return on plan assets*  7.8%  8.3%   7.8%  8.3%  8.3%  8.9%  N/A    N/A   N/A 
Rate of compensation increase  4.0%  4.9%   4.0%  5.1%  4.0%  5.4%  4.1%   4.1%  4.1%
       
                                       
  Pension Benefits    
  2005   2004  2003  Other Benefits 
  U.S.  Int'l.   U.S.  Int'l.  U.S.  Int'l.  2005   2004  2003 
         
Assumptions used to determine benefit obligations Discount rate  5.5%  5.9%   5.8%  6.4%  6.0%  6.8%  5.6%   5.8%  6.1%
Rate of compensation increase  4.0%  5.1%   4.0%  4.9%  4.0%  4.9%  4.0%   4.1%  4.1%
Assumptions used to determine net periodic benefit cost Discount rate1,2
  5.5%  6.4%   5.9%  6.8%  6.3%  7.1%  5.8%   6.1%  6.8%
Expected return on plan assets1,2
  7.8%  7.9%   7.8%  8.3%  7.8%  8.3%  N/A    N/A   N/A 
Rate of compensation increase2
  4.0%  5.0%   4.0%  4.9%  4.0%  5.1%  4.0%   4.1%  4.1%
       
  
*
1
Discount rate and expected rate of return on plan assets were reviewed and updated as needed on a quarterly basis for the main U.S. pension plan.
 
2
The 2005 discount rate, expected return on plan assets and rate of compensation increase reflect the remeasurement of the Unocal benefit plans at July 31, 2005, due to the acquisition of Unocal.

Expected Return on Plan Assets The company employs a rigorous process to determine the estimates of the long-term rate of return on pension assets. These estimates are primarily driven by actual historical asset-class returns, an assessment of expected future performance, and advice from external actuarial firms while incorporatingand the incorporation of specific asset classasset-class risk factors. Asset allocations are regularlyperiodically updated using pension plan asset/liability studies, and the determination of the company’s estimates of long-term rates of return are consistent with these studies.
     There have been no changes in the expected long-term rate of return on plan assets since 2002 for U.S. plans, which account for about 7072 percent of the company’s pension plan assets. At December 31, 2004,2005, the estimated long-term rate of return on U.S. pension plan assets was 7.8 percent.
     The year-end market-related value of assets of the major U.S. pension plan assets used in the determination of pension expense was based on the market values in the preceding three months preceding the year-end measurement date, as opposed to the maximum allowable period of five years under U.S. accounting rules. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and yet still be contemporaneous to the end of the year. For other plans, outside the U.S., market value of assets as of the measurement date is used in calculating the pension expense.
Other Benefit AssumptionsDiscount Rate Effective January 1,The discount rate assumptions used to determine U.S. and international pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality fixed-income debt instruments. At December 31, 2005, the company amended its main U.S. postretirement medical plan to limit future increasesselected a


FS-52

NOTE 21.EMPLOYEE BENEFIT PLANS — Continued
5.5 percent discount rate (shown in the company contribution. For current retirees,table on page FS-52) based on Moody’s Aa Corporate Bond Index and a cash flow analysis using the increase in company contribution is cappedCitigroup Pension Discount Curve. The discount rates at 4 percent each year. For future retirees, the 4 percent cap will be effective at retirement. Before retirement, the assumed health care cost trend rates start with 10.6 percent inend of 2004 and gradually drop to 4.82003 were 5.8 percent for 2010 and beyond. Once the employee elects to retire, the trend rates are capped at 4 percent.6 percent, respectively.
Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2003,2005, for the main U.S. postretirement medical plan, the assumed heathhealth care cost trend rates start with 8.410 percent in 20032006 and gradually decline to 4.55 percent for 20072011 and beyond. For this measurement at December 31, 2004, the assumed health care cost trend rates started with 9.5 percent in 2005 and gradually declined to 4.8 percent for 2010 and beyond. In both measurements, increases in the company’s contributions are capped at 4 percent effective at retirement.
     Assumed health care cost-trend rates have a significant effect on the amounts reported for retiree health care costs. A one-percentage-point change of one percentage point in the assumed health care cost-trend rates would have the following effects:


FS-48

4NOTE 22.EMPLOYEE BENEFIT PLANS – Continued
         
 1 Percent 1 Percent 
 Increase Decrease 
 
Effect on total service and interest cost components $8  $(9)
Effect on postretirement benefit obligation $ 126  $ (184)
 
         
  1 Percent  1 Percent 
  Increase  Decrease 
 
Effect on total service and interest cost components $18  $(15)
Effect on postretirement benefit obligation $86  $(98)
 

Plan Assets and Investment Strategy The company’s pension plan weighted-average asset allocationallocations at December 31 by asset category isare as follows:
                            
 U.S. International  U.S. International 
Asset Category 2004 2003 2004 2003  2005 2004 2005 2004 
       
Equities  70%  70%   57%  55%  69%  70%   60%  57%
Fixed Income  21%  21%   42%  43%  21%  21%   39%  42%
Real Estate  9%  8%   1%  2%  9%  9%   1%  1%
Other –  1%  – –   1% –   – – 
       
Total  100%  100%   100%  100%  100%  100%   100%  100%
      

     The pension plans invest primarily in asset categories with sufficient size, liquidity and cost efficiency to permit investments of reasonable size. The pension plans invest in asset categories that provide diversification benefits and are easily measured. To assess the plans’ investment performance, long-term asset allocation policy benchmarks have been established.
     For the primary U.S. pension plan, the ChevronTexacoChevron Board of Directors has established the following approved asset allocation ranges: Equities 40-7040–70 percent, Fixed Income 20-6520–60 percent, Real Estate 0-150–15 percent and Other 0–5 percent. The significant international pension plans also have established maximum and minimum asset allocation ranges that vary by each plan. Actual asset allocation within approved ranges is based on a variety of current economic and market conditions and consideration of specific asset category risk.
     Equities include investments in the company’s common stock in the amount of $8$13 and $6$8 at December 31, 20042005 and 2003,2004, respectively. The “Other” asset category includes minimal investments in private equityprivate-equity limited partnerships.
      
Cash Contributions and benefitBenefit Payments In 2004,2005, the company contributed $1,332$794 and $311$228 to its U.S. and international pension plans, respectively. In 2005,2006, the company expects contributions to be approximately $250$300 and $150$200 to its U.S. and international pension plans, respectively. Actual contribution amounts are dependent upon investmentplan-investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.
     The company anticipates paying other postretirement benefits of approximately $220 in 2005,2006, as compared with $199$226 paid in 2004.2005.
     The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10ten years:

                               
 Pension Benefits  Other  Pension Benefits  Other 
 U.S. Int’l. Benefits  U.S. Int'l. Benefits 
  
2005 $489 $144 $217 
2006 $507 $150 $186  $788 $177 $220 
2007 $524 $160 $190  $639 $185 $218 
2008 $540 $171 $193  $674 $195 $224 
2009 $553 $180 $197  $714 $202 $231 
2010-2014 $2,912 $1,038 $1,028 
2010 $729 $212 $237 
2011–2015 $ 3,803 $ 1,240 $ 1,238 
 
Employee Savings Investment Plan Eligible employees of ChevronTexacoChevron and certain of its subsidiaries participate in the ChevronTexacoChevron Employee Savings Investment Plan (ESIP). In 2002, the Employees Thrift Plan of Texaco Inc., Employees Savings Plan of ChevronTexaco Global Energy Inc. (formerly Caltex Corporation), Stock Plan of ChevronTexaco Global Energy, Inc., and Employees Thrift Plan of Fuel and Marine Marketing LLC were merged into the ChevronTexaco ESIP.
     Charges to expense for the ESIP represent the company’s contributions to the plan, which are funded either through the purchase of shares of common stock on the open market or through the release of common stock held in the leveraged employee stock ownership plan (LESOP), which is discussed below. Total company matching contributions to employee accounts within the ESIP were $145, $139 $136 and $136 in 2005, 2004 2003 and 2002,2003, respectively. This cost was reduced by the value of shares released from the LESOP totaling $(138)$(4), $(138) and $(23) in 2005, 2004 and $(73) in 2004, 2003, and 2002, respectively. The remaining amounts, totaling $141, $1 and $113 in 2005, 2004 and $63 in 2004, 2003, and 2002, respectively, represent open market purchases.
      
Employee Stock Ownership Plan Within the ChevronTexacoChevron Employee Savings Investment Plan (ESIP), is an employee stock ownership plan (ESOP). In 1989, Chevron established a leveraged employee stock ownership plan (LESOP) as a constituent part of the ESOP. The LESOP provides partial prefunding of the company’s future commitments to the ESIP.
     As permitted by American Institute of Certified Public Accountants (AICPA) Statement of Position 93-6,“Employers’ Accounting for Employee Stock Ownership Plans,”the company has elected to continue its practices, which are based on AICPA Statement of Position 76-3,“Accounting Practices for Certain Employee Stock Ownership Plans,”and subsequent consensus of the EITF of the FASB. The debt of the LESOP


FS-53

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
NOTE 21.EMPLOYEE BENEFIT PLANS – Continued
is recorded as debt, and shares pledged as collateral are reported as “Deferred compensation and benefit plan trust” inon the Consolidated Balance Sheet and the Consolidated Statement of Stockholders’ Equity.
     The company reports compensation expense equal to LESOP debt principal repayments less dividends received and used by the LESOP for debt service. Interest accrued on the LESOP debt is recorded as interest expense. Dividends paid on LESOP shares are reflected as a reduction of retained earnings. All LESOP shares are considered outstanding for earnings-per-share computations.
     Total expenses (credits) expenses recorded for the LESOP were $94, $(29), and $24 in 2005, 2004 and $98 in 2004, 2003, and 2002, respectively, including $18, $23 $28 and $32$28 of interest expense related to LESOP debt and a charge (credit) charge to compensation expense of $76, $(52), $(4) and $66.$(4).
     Of the dividends paid on the LESOP shares, $55, $52 $61 and $49$61 were used in 2005, 2004 2003 and 2002,2003, respectively, to service LESOP debt. Included in the 2004 amount was a repayment of debt entered into in 1999 to pay interest on the ESOP debt. Interest expense on this debt was recognized and reported as LESOP interest expense in 1999. In addition, the company made no contributions in 20042005 and contributions2003 of $26$98 and $102 in 2003


FS-49

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
4NOTE 22.EMPLOYEE BENEFIT PLANS — Continued
and 2002,$26, respectively, to satisfy LESOP debt service in excess of dividends received by the LESOP.
      In January 2005, the company contributed $98 to permit No contributions were required in 2004 as dividends received by the LESOP were sufficient to make a $144satisfy LESOP debt service payment, which included a principal payment of $113.service.
     Shares held in the LESOP are released and allocated to the accounts of plan participants based on debt service deemed to be paid in the year in proportion to the total of current-year and remaining debt service. LESOP shares as of December 31, 20042005 and 2003,2004, were as follows:
          
Thousands 2004   2003 
    
Allocated shares*  24,832    24,198 
Unallocated shares  9,940    13,634 
    
Total LESOP shares  34,772    37,832 
    
*2003 share amounts restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in 2004.
          
Thousands 2005   2004 
    
Allocated shares  23,928    24,832 
Unallocated shares  9,163    9,940 
    
Total LESOP shares  33,091    34,772 
    
 
Benefit Plan TrustTrusts Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2004,2005, the trust contained 14.2 million shares of ChevronTexacoChevron 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.
     Unocal established various grantor trusts to fund obligations under some of its benefit plans, including the deferred compensation and supplemental retirement plans.
     At December 31, 2005, trust assets totaled $130 and were invested primarily in interest-earning accounts.
Management Incentive Plans ChevronTexacoChevron has two incentive plans, the Management Incentive Plan (MIP) and the Long-Term Incentive Plan (LTIP), for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. The plans were expanded in 2002 to include former employees of Texaco and Caltex. The MIP is an annual cash incentive plan that links awards to performance results of the prior year. The cash awards may be deferred by the recipients by conversion to stock units or other investment fund alternatives. Awards under the LTIP may take the form of, but are not limited to, stock options, restricted stock, stock units and nonstock grants. Texaco also had a cash incentive program and a Stock Incentive Plan (SIP) that included stock options, restricted stock and other incentive awards for executives, directors and key employees. Awards under the Caltex LTIP were in the form of performance units and stock appreciation rights. alternatives.Aggregate charges to expense for these management incentive plans, excluding expense related toMIP were $155, $147 and $125 in 2005, 2004 and 2003, respectively. Awards under the LTIP and SIPconsist of stock options and restricted stock awards thatother share-based compensation which are discusseddescribed more fully in Note 23 that follows, were $214, $148 and $48 in 2004, 2003 and 2002, respectively. Included in this amount for 2004 was $14 related to stock appreciation rights.22 below.
 
Other Incentive Plans The company has a program that provides eligible employees, other than those covered by MIP and LTIP, with an annual cash bonus if the company achieves certain financial and safety goals. Additionally, in August 2005, the company assumed responsibility for the remaining pro-rated cash bonuses under the Unocal Annual Incentive Plan. Charges for the programprograms were $324, $339 and $151 in 2005, 2004 and $158 in 2004, 2003, and 2002, respectively.

NOTE 23.22.
STOCK OPTIONS AND OTHER SHARE-BASED COMPENSATION
Effective July 1, 2005, the company adopted the provisions of Financial Accounting Standards Board (FASB) Statement No. 123R,“Share-Based Payment,”(FAS 123R) for its share-based compensation plans. The company applies APBpreviously accounted for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25,“Accounting for Stock Issued to Employees,”(APB 25) and related interpretations in accountingand disclosure requirements established by FAS 123,“Accounting for its stock-based compensation programs. Stock-based compensation expense (credit) recognized in connection with these programsStock-Based Compensation.”
     The company adopted FAS 123R using the modified prospective method and, the stock appreciation rights discussed above was $16, $2 and $(2) in 2004, 2003 and 2002, respectively.
accordingly, results for prior periods have not been restated. Refer to Note 1, beginning on page FS-30FS-34, for the pro forma effectseffect on net income and earnings per share hadas if the company had applied the fair-value-recognition provisionsfair-value recognition of FAS No. 123.123 for periods prior to adoption of FAS 123R and the actual effect on net income and earnings per share for periods after adoption of FAS 123R.
     For 2005, compensation expense charged against income for the first time for stock options was $65 ($42 after tax). In addition, compensation expense charged against income for stock appreciation rights, performance units and restricted stock units was $59 ($39 after tax), $65 ($42 after tax) and $25 ($16 after tax) for 2005, 2004 and 2003, respectively. There were no significant capitalized stock-based compensation costs at December 31, 2005.
     Cash received from option exercises under all share-based payment arrangements for 2005, 2004 and 2003 was $297, $385 and $32, respectively. Actual tax benefits realized for the tax deductions from option exercises was $71, $49 and $6 for 2005, 2004 and 2003, respectively.



FS-54

NOTE 22.STOCK OPTIONS AND OTHER SHARE-BASED
COMPENSATION – Continued
     Cash paid to settle performance units and stock appreciation rights was $110, $23 and $11 for 2005, 2004 and 2003, respectively. Cash paid in 2005 included $73 million for Unocal awards paid under change-in-control plan provisions.
     At adoption of FAS 123R, the impact of measuring stock appreciation rights at fair value instead of intrinsic value resulted in an insignificant charge against income in the third quarter 2005. For restricted stock units, FAS 123R required that unrecognized compensation amounts presented in “Deferred compensation and benefit plan trust” on the Consolidated Balance Sheet be reclassified against the appropriate equity accounts. This resulted in a reclassification of $7 to “Capital in excess of par value.”
     Prior to the adoption of FAS 123R, the company presented all tax benefits of deductions resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. FAS 123R requires the cash flow resulting from the tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. Refer to Note 3, beginning on page FS-37, for information on excess tax benefits.
     In November 2005, the FASB issued a Staff Position FAS 123R-3 (FSP FAS 123R-3),“Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,”which provides a one-time transition election for companies to follow in calculating the beginning balance of the pool of excess tax benefits related to employee compensation and a simplified method to determine the subsequent impact on the pool of employee awards that are fully vested and outstanding upon the adoption of FAS 123R. Under the FSP, the company must decide by November 2006 whether to make this one-time transition election, which may provide some administrative relief in calculating the future tax effects of stock option issuances. Whether or not the one-time election is made, the company anticipates no significant difference in the amount of tax expense recorded in future periods.
     In the discussion below, the references to share price and number of shares have been adjusted for the two-for-one stock split in September 2004, which is discussed in Note 3 on page FS-33.2004.
      
Broad-Based Employee Stock Options In 1998, Chevron granted to all eligible employees options that varied from 200 to 600 shares of stock or equivalents, dependent on the employee’s salary or job grade. These options vested after two years in February 2000 and expire in February 2008. Options for 9,641,600 shares were awarded at an exercise price of $38.15625 per share. Outstanding option shares were 4,018,350 at the end of 2002. In 2003, exercises of 23,260 and forfeitures of 122,100 reduced the outstanding option shares to 3,872,990 at the end of the year. In 2004, exercises of 1,720,946 and forfeitures of 42,540 reduced the outstanding option shares to 2,109,504 at the end of the year. The company recorded expense (credit) of $2, $2 and $(2) for these options in 2004, 2003 and 2002, respectively.
     The fair value of each option share on the date of grant under FAS No. 123 was estimated at $9.54 using the average results of Black-Scholes models for the preceding 10 years. The 10-year averages of each assumption used by the Black-Scholes models were: a risk-free interest rate of 7.0 percent, a dividend yield of 4.2 percent, an expected life of seven years and a volatility of 24.7 percent.
Long-Term Incentive Plan (LTIP) Stock options grantedAwards under the LTIP extend for 10 years frommay take the dateform of, grant. Effective withbut are not limited to, stock options, granted in June 2002, one-third of the options vest on each of the first, secondrestricted stock, restricted stock units, stock appreciation rights, performance units 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.non-stock grants. For a 10-year period after April 2004, no more than 160 million shares may be issued under the Plan,LTIP, and no more than 64 million of those shares may be in a form other than a stock option, stock appreciation right or award requiring full payment for shares by the award recipient. This provision replaced a formula that restricted annual awards
     Stock options and stock appreciation rights granted under the LTIP extend for 10 years from grant date. Effective with options granted in June 2002, one-third of each award vests on the first, second and third anniversaries of the date
of grant. Prior to no more thanthis change, options granted by Chevron vested one percentyear after the date of shares outstandinggrant. Performance units granted under the LTIP extend for 3 years from grant date and are settled in cash at the beginning of each year. Not counted against the 160 million-share maximum are shares issued as a resultend of the exercise options that were granted beforeperiod. Settlement amounts are based on achievement of performance targets relative to major competitors over the change in formula in 2004.period, and payments are indexed to the company’s stock price.
Texaco Stock Incentive Plan (Texaco SIP) On the closing of the mergeracquisition of Texaco in October 2001, outstanding options granted under the Texaco SIP were converted to ChevronTexaco options at the merger exchange rate of 0.77.Chevron options. These options retained a provision for being restored, options. This featurewhich enables a participant who exercises a stock option by exchanging previously acquired common stockto receive new options equal to the number of shares exchanged or who has shares withheld to satisfy tax withholding obligations to receive new options equal to the number of shares exchanged or withheld. The restored options are fully exercisable six months after the date of grant, and the exercise price is the fair market value of the common stock on the day the restored option is granted. Restricted shares



FS-50

4NOTE 23.STOCK OPTIONS – Continued

granted under the former Texaco plan contained a performance element that had to be satisfied in order for all or a specified portion of the shares to vest. Upon the merger, all restricted shares became vested and converted to ChevronTexaco shares at the merger exchange ratio of 0.77. Apart from the restored options, no further awards may be granted under the former Texaco plans. No amount
Unocal Share-Based Plans (Unocal Plans) On the closing of the acquisition of Unocal in August 2005, outstanding stock options and stock appreciation rights granted under various Unocal Plans were exchanged for these plans was chargedfully vested Chevron options at a conversion ratio of 1.07 Chevron shares for each Unocal share. These awards retained the same provisions as the original Unocal Plans. Awards issued prior to compensation expense2004 generally may be exercised for up to 3 years after termination of employment (depending upon the terms of the individual award agreements), or the original expiration date, whichever is earlier. Awards issued since 2004 generally remain exercisable until the end of the normal option term if termination of employment occurs prior to August 10, 2007. Other awards issued under the Unocal Plans, including restricted stock, stock units, restricted stock units and performance shares, became vested at the acquisition date, and shares or cash were issued to recipients in 2004, 2003 or 2002.accordance with change-in-control provisions of the plans.


FS-55

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
NOTE 22.STOCK OPTIONS AND OTHER SHARE-BASED
COMPENSATION — Continued
     The fair market valuevalues of each stock optionoptions and stock appreciation rights granted is estimatedin 2005, 2004 and 2003 were measured on the date of grant under FAS No. 123 using the Black-Scholes option-pricing model, with the following weighted-average assumptions:
              
  2004   2003  2002 
    
ChevronTexaco plans:             
Expected life in years  7    7   7 
Risk-free interest rate  4.4%   3.1%  4.6%
Volatility  16.5%   19.3%  21.6%
Dividend yield  3.7%   3.5%  3.0%
Texaco plans:             
Expected life in years  2    2   2 
Risk-free interest rate  2.5%   1.7%  1.6%
Volatility  17.8%   22.0%  24.1%
Dividend yield  3.8%   3.9%  3.1%
    
              
  Year ended December 31 
  2005   2004  2003 
    
Chevron LTIP:
             
Expected term in years1
  6.4    7.0   7.0 
Volatility2
  24.5%   16.5%  19.3%
Risk-free interest rate based on zero coupon U.S. treasury note  3.8%   4.4%  3.1%
Dividend yield  3.4%   3.7%  3.5%
Weighted-average fair value per option granted $11.66   $7.14  $5.51 
Texaco SIP:
             
Expected term in years1
  2.1    2.0   2.0 
Volatility2
  18.6%   17.8%  22.0%
Risk-free interest rate based on zero coupon U.S. treasury note  3.8%   2.5%  1.7%
Dividend yield  3.4%   3.8%  3.9%
Weighted-average fair value per option granted $6.09   $4.00  $4.03 
Unocal Plans:3
             
Expected term in years1
  4.2    –   – 
Volatility2
  21.6%   –   – 
Risk-free interest rate based on zero coupon U.S. treasury note  3.9%   –   – 
Dividend yield  3.4%   –   – 
Weighted-average fair value per option granted $21.48   $–  $– 
    

     The Black-Scholes weighted-average fair value of the Chevron-Texaco options granted during 2004, 2003 and 2002 was $7.14, $5.51 and $9.30 per share, respectively, and the weighted-average fair value of the SIP restored options granted during 2004, 2003 and 2002 was $4.00, $4.03 and $5.15 per share, respectively.

1
Expected term is based on historical exercise and post-vesting cancellation data.
2
Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term.
3
Represents options converted at the acquisition date.
     A summary of the status of stock options awardedoption activity under the company’s LTIP as well as the former Texaco and Unocal plans for 2004, 2003 and 2002 follows:is presented below:
         
     Weighted-
Average		 
  Options
(thousands)		  Exercise
Price		 
 
Outstanding at December 31, 2001  45,240  $40.57 
 
Granted  6,582   43.07 
Exercised  (3,636)  36.51 
Restored  2,548   44.69 
Forfeited  (1,490)  44.05 
 
Outstanding at December 31, 2002  49,244  $41.33 
 
Granted  9,320   36.70 
Exercised  (1,458)  25.07 
Restored  120   41.35 
Forfeited  (1,966)  42.70 
 
Outstanding at December 31, 2003  55,260  $40.93 
 
Granted  9,164   47.06 
Exercised  (14,308)  39.87 
Restored  4,814   48.84 
Forfeited  (578)  43.94 
 
Outstanding at December 31, 2004  54,352  $42.90 
 
Exercisable at December 31        
2002  42,890  $41.07 
2003  42,554  $41.62 
2004  35,547  $42.15 
 

                 
          Weighted-    
      Weighted-  Average    
      Average  Remaining  Aggregate 
  Shares  Exercise  Contractual  Intrinsic 
  (Thousands)  Price  Term  Value 
 
Outstanding at January 1, 2005
  54,440  $42.89         
Granted  8,718  $56.76         
Granted in Unocal acquisition  5,313  $35.02         
Exercised*  (13,946) $44.19         
Restored  5,596  $58.41         
Forfeited*  (597) $49.19         
Outstanding at December 31, 2005
  59,524  $45.32  6.1 yrs. $694 
 
Exercisable at December 31, 2005
  40,033  $42.18  5.2 yrs. $586 
 
*Includes fully-vested Chevron options exchanged for outstanding Unocal options.
     The following table summarizes information abouttotal intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised
during 2005, 2004 and 2003 was $258, $129 and $17, respectively.
     At adoption of FAS 123R, the company elected to amortize newly issued graded awards on a straight-line basis over the requisite service period. In accordance with FAS 123R implementation guidance issued by the staff of the Securities and Exchange Commission, the company accelerates the vesting period for retirement-eligible employees in accordance with vesting provisions of the company’s share-based compensation programs for awards issued after adoption of FAS 123R. As of December 31, 2005, there was $89 of total unrecognized before-tax compensation cost related to nonvested share-based compensation arrangements granted or restored under the plans. That cost is expected to be recognized over a weighted-average period of 2.3 years.
     At January 1, 2005, the number of LTIP performance units outstanding was equivalent to 2,673,482 shares. During 2005, 709,900 units were granted, 1,012,932 units vested with cash proceeds distributed to recipients, and 24,434 units were forfeited. At December 31, 2005, units outstanding were 2,346,016, and the value of the liability recorded for these instruments was $83. In addition, outstanding stock appreciation rights that were awarded under various LTIP and former Texaco and Unocal programs totaled approximately 800,000 equivalent shares as of December 31, 2005. A liability of $16 was recorded for these awards.
Broad-Based Employee Stock Options In addition to the plans described above, Chevron granted all eligible employees stock options or equivalents in 1998. The options vested after two years, in February 2000, and expire after 10 years, in February 2008. A total of 9,641,000 options were awarded with an exercise price of $38.15625 per share.
     The fair value of each option on the date of grant was estimated at $9.54 using the Black-Scholes model for the preceding 10 years. The assumptions used in the model, based on a 10-year average, were: a risk-free interest rate of 7 percent, a dividend yield of 4.2 percent, an expected life of 7 years and a volatility of 24.7 percent.
     At January 1, 2005, the number of broad-based employee stock options outstanding including those from former Texaco plans, atwas 2,109,504. During 2005, exercises of 397,500 shares and forfeitures of 29,100 shares reduced outstanding options to 1,682,904. As of December 31, 2004:2005, these instruments had an aggregate intrinsic value of $31 and the remaining contractual term of these options was 2.1 years. The total intrinsic value of these options exercised during 2005 and 2004 was $9 and $16, respectively. Exercises in 2003 were insignificant.
                          
Options Outstanding  Options Exercisable 
      Weighted-        
      Average  Weighted-      Weighted- 
  Number  Remaining  Average  Number  Average 
Range of Outstanding  Contractual  Exercise  Exercisable  Exercise 
Exercise Prices (thousands)  Life (years)  Price  (thousands)  Price 
   
$15   to    $25  513   0.55  $24.09   513  $24.09 
25   to      35  875   1.86   32.94   875   32.94 
35   to      45  33,061   6.13   40.97   26,031   41.71 
45   to      55  19,846   6.54   47.02   8,128   45.69 
55   to      65  57   2.41   55.21   –   – 
   
$15   to    $65  54,352   6.15  $42.90   35,547  $42.15 
 

NOTE 24.23.
OTHER CONTINGENCIES AND COMMITMENTS
Income Taxes The company estimatescalculates its income tax expense and liabilities annually.quarterly. These liabilities generally are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been estimated.calculated. The U.S. federal income tax liabilities have been settled through 1996 for Chevron (formerly ChevronTexaco (formerly Chevron Corporation), and 1997 for ChevronTexacoChevron Global



FS-56

NOTE 23.OTHER CONTINGENCIES AND
COMMITMENTS – Continued
Energy Inc. (formerly Caltex)Caltex Corporation), Unocal Corporation (Unocal) and 1991 for Texaco Inc. (Texaco). California franchise tax liabilities have been settled through 1991 for Chevron, 1998 for Unocal 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.
 
Guarantees At December 31, 2004,2005, the company and its subsidiaries provided, either directly or indirectly, guarantees of $963$985 for notes and other contractual obligations of affiliated companies and $130$294 for third parties, as described by major category below. There are no material amounts being carried as liabilities for the company’s obligations under these guarantees.
     Of the $963$985 guarantees provided to affiliates, $774 relate$806 related to borrowings for capital projects or general corporate purposes. These guarantees were undertaken to achieve lower interest rates and generally cover the construction periodperiods of the capital projects. Included in these amounts are Unocal-related guarantees of approximately $230 associated with a construction completion guarantee for the debt financing of Unocal’s equity interest in the Baku-Tbilisi-Ceyhan (BTC) crude oil pipeline project. Approximately 9095 percent of the amounts$806 guaranteed will expire by 2009,between 2006 and 2010, with the remaining guarantees expiring by the end of 2015. Under the terms of the guarantees, the company would be required to fulfill the guarantee should an affiliate be in default of its loan terms, generally for the full amounts disclosed. There are no recourse provisions, and no assets are held as collateral for these guarantees. The $189 balanceother guarantees of the $963 represents$179 represent obligations in connection with pricing of power purchasepower-purchase agreements for certain of the company’s cogeneration affiliates. Under the terms of these guarantees, the company may be required to make payments under certain conditions if the affiliates do not perform under the agreements. There are no provisions for recourse to third parties, and no assets are held as collateral for these pricing guarantees.
     Guarantees of $130 have beenOf the $294 in guarantees provided to third parties, including approximately $40 of$150 related to construction loans to host governments of certain of the company’s international upstream operations. The remaining guarantees of $90$144 were provided



FS-51

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
4NOTE 24.OTHER CONTINGENCIES AND COMMITMENTS – Continued
principally as conditions of sale of the company’s interest in certain operations, to provide a source of liquidity to the guaranteed parties and in connection with company marketing programs. No amounts of the company’s obligations under these guarantees are recorded as liabilities. About 7085 percent of the total amounts guaranteed will$294 in guarantees expire by 2009.2010, with the remainder expiring after 2010. The company would be
required to perform under the terms of the guarantees should an entity be in default of its loan or contract terms, generally for the full amounts disclosed. Approximately $70$85 of the guarantees have recourse provisions, which enable the company to recover any payments made under the terms of the guarantees from securities held over the guaranteed parties’ assets.
     At December 31, 2004, ChevronTexaco2005, Chevron also had outstanding guarantees for approximately $215about $190 of Equilon debt and leases. Following the February 2002 disposition of its interest in Equilon, the company received an indemnification from Shell Oil Company (Shell) for any claims arising from the guarantees. The company has not recorded a liability for these guarantees. Approximately 4550 percent of the amounts guaranteed will expire by 2009,within the 2006 through 2010 period, with the guarantees of the remaining amounts expiring by 2019.
      
Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell Oil Company (Shell) and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover certain contingent liabilities, including those associated with the Unocal patent litigation. The company would be required to perform shouldif the indemnified liabilities become actual losses. ShouldWere that to occur, the company could be required to make future payments up to $300. Through the end of 2004,2005, the company paid approximately $28$38 under these contingencies and had agreed to pay approximately $10 additional under an award of arbitration, subject to minor adjustments yet to be resolved.indemnities. The company mayexpects to receive additional requests for indemnification payments in the future.
     The company has also provided indemnities relating to contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the periods of Texaco’s ownership interestsinterest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims relating to Equilon indemnities must be asserted either as early as February 2007, or no later than February 2009, and claims relating to Motiva must be asserted no later than February 2012. Under the terms of the indemnities, there is no maximum limit on the amount of potential future payments. The company has not recorded any liabilities for possible claims under these indemnities. The company posts no assets as collateral and has made no payments under the indemnities.
     The amounts payable for the indemnities described above are to be net of amounts recovered from insurance carriers and others and net of liabilities recorded by Equilon or Motiva prior to September 30, 2001, for any applicable incident.
     In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets of Unocal’s 76 Products Company business that existed prior to its sale in 1997. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments by the company; however, the purchaser shares certain costs under this indemnity up to an aggregate cap of $200. Claims relating to these indemnities must be asserted by April 2022. Through the end of 2005,


FS-57

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
NOTE 23.OTHER CONTINGENCIES AND
COMMITMENTS — Continued
approximately $113 had been applied to the cap, which includes payments made by either Unocal or Chevron totaling $80.
Securitization The company securitizes certain retail and trade accounts receivable in its downstream business through the use
of qualifying SPEs.Special Purpose Entities (SPEs). At December 31, 2004,2005, approximately $1,200, representing about 107 percent of ChevronTexaco’sChevron’s total current accounts receivables balance, were securitized. ChevronTexaco’sChevron’s total estimated financial exposure under these securitizations at December 31, 2004,2005, was approximately $50.$60. These arrangements have the effect of accelerating ChevronTexaco’sChevron’s collection of the securitized amounts. In the event that the SPEs experience major defaults in the collection of receivables, ChevronTexacoChevron believes that it would have no loss exposure connected with third-party investments in these securitizations.
 
Long-Term Unconditional Purchase Obligations and Commitments, Throughput Agreements, and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, throughput agreements, and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are 2005 – $1,600; 2006 – $1,700;— $2,200; 2007 – $1,600;— $1,900; 2008 – $1,500;— $1,800; 2009 – $1,500;— $1,800; 2010 — $500; 2011 and after – $2,300.— $3,800. Total payments under the agreements were approximately $2,100 in 2005, $1,600 in 2004 and $1,400 in 2003 and $1,200 in 2002.2003.
     The most significant take-or-pay agreement calls for the company to purchase approximately 55,000 barrels per day of refined products from an equity affiliate refiner in Thailand. This purchase agreement is in conjunction with the financing of a refinery owned by the affiliate and expires in 2009. The future estimated commitments under this contract are: 2005 – $1,200; 2006 – $1,200;— $1,300; 2007 –— $1,300; 2008 –— $1,300; and 2009 –— $1,300. Additionally, inUnder the terms of a 2004 agreement, the company entered into a 20-year agreementexercised its option in 2005 to acquire additional regasification capacity at the Sabine Pass LNG terminal.Liquefied Natural Gas Terminal. Payments of $1,200$2.5 billion over the 20-year period are expected to commence in 2010.2009.
      
Minority Interests The company has commitments of approximately $172$200 related to minority interests in subsidiary companies.
 Texaco Capital LLC, a wholly owned financial subsidiary, issued Deferred Preferred Shares, Series C, in December 1995. In February 2005, the company redeemed current obligations related to minority interests of approximately $140.
Environmental The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or
ameliorate the effects on the environment of prior release of chemical or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, and land development areas, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.
     Although the company has provided for known environmental obligations that are probable and reasonably estimable,


FS-52

4NOTE 24.OTHER CONTINGENCIES AND COMMITMENTS — Continued
the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had or will have any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemical companies.
     ChevronTexaco’sChevron’s environmental reserve as of December 31, 2004,2005, was $1,047.$1,469. Included in this balance were liabilities assumed in connection with the acquisition of Unocal, which relate primarily to sites that had been previously divested or closed by Unocal. The sites included, but were not limited to, former refineries, transportation and distribution facilities and service stations, crude oil and natural gas fields and mining operations, as well as active mining operations.
     The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end 20042005 had a recorded liability that was material to the company’s financial position, results of operations or liquidity.
     Included in the year-end 20042005 balance was $107$139 related to sites for which ChevronTexacoChevron had been identified by the U.S. Environmental Protection Agency or other regulatory agencies under the provisions of the federal Superfund law or analogous state laws as a “potentially responsible party” or otherwise involved in the remediation.
     Of the remaining year-end 20042005 environmental reserves balance of $940, $712$1,330, $855 related to more than 2,000approximately 2,250 sites for the company’s U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals) and pipelines. The remaining $228$475 was associated with various sites in the international downstream ($111)101), upstream ($69)257), chemicals ($50) and chemicalsother ($48)67). Liabilities at all sites, whether operating, closed or divested, were primarily associated with the company’s plans and activities to


FS-58

NOTE 23.OTHER CONTINGENCIES AND
COMMITMENTS — Continued
remediate soil or groundwater contamination or both. These and other activities include one or more of the following: site assessment; soil excavation; offsite disposal of contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid and vapor from soil; groundwater extraction and treatment; and monitoring of the natural attenuation of the contaminants.
 
Global Operations ChevronTexacoChevron and its affiliates conduct business activities in approximately 180 countries. Areas in which the company and its affiliates have significant operations include the United States, Canada, Australia, the United Kingdom, Norway, Denmark, France, the Netherlands, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, Republic of the Congo, Angola, Nigeria, Chad, South Africa, the Democratic Republic of the Congo, Indonesia, Bangladesh, the Philippines, Myanmar, Singapore, China, Thailand, Vietnam, Cambodia, Azerbaijan, Kazakhstan, Venezuela, Argentina, Brazil, Colombia, Trinidad and Tobago, and South Korea. The company’s CPCCaspian Pipeline Consortium (CPC) affiliate operates in Russia and Kazakhstan. The company’s TCOTengizchevroil (TCO) affiliate operates in Kazakhstan. Through an affiliate, the company participates in the development of the Baku-Tbilisi-Ceyhan (BTC) pipeline through Azerbaijan, Georgia and Turkey. Also through an affiliate, the company has an interest in the Chad/Cameroon pipeline. The company’s Petrolera Ameriven affiliate operates the Hamaca project in Venezuela. The company’s CPChem affiliate manufactures and markets a wide range of petrochemicals on a worldwide basis, with manufacturing facilities in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar, Mexico and Belgium.
     The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates, including the United States. As has occurred in the past, actions could be taken by host governments to increase public
ownership of the company’s partially or wholly owned businesses or assets or to impose additional taxes or royalties on the company’s operations or both.
     In certain locations, host governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries. Internal unrest, acts of violence or strained relations between a host government and the company or other governments may affect the company’s operations. Those developments have at times significantly affected the company’s related operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries.
Equity Redetermination For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude oil and natural gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for ChevronTexaco’sChevron’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 currentlyChevron 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 ChevronTexacoChevron is estimated at about $50. The timing of the settlement and the exact amount within this range of estimates wereare uncertain.
 
Other Contingencies ChevronTexacoChevron 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 25.24.
FAS 143 — ASSET RETIREMENT OBLIGATIONS
The company adopted Financial Accounting Standards Board Statement (FASB) No. 143,“Accounting for Asset Retirement Obligations”Obligations,”(FAS 143), effective January 1, 2003. This accounting standard applies to the fair value of a liability for an asset retirement obligation that is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Obligations associated with the retirement of these assets require recognition in certain circumstances: (1) the present value of a liability and offsetting asset for an ARO, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates. FAS 143 primarily affects the company’s accounting for crude oil and natural gas producing assets and differs in several respects from previous accounting under FAS 19,“Financial Accounting and Reporting by Oil and Gas Producing Companies.”



CHEVRONTEXACO CORPORATION 2004 ANNUAL REPORT53

FS-53

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
4NOTE 25.FAS 143 – ASSET RETIREMENT OBLIGATIONS – Continued
     In the first quarter 2003, the company recorded a net after-tax charge of $200 for the cumulative effect of the adoption of FAS 143, including the company’s share of amounts attributable to equity affiliates. The cumulative-effect adjustment also increased the following balance sheet categories: “Properties, plant and equipment,” $2,568; “Accrued liabilities,” $115; and “Deferred credits and other noncurrent



FS-59

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
NOTE 24.ASSET RETIREMENT OBLIGATIONS — Continued
obligations,” $2,674. “Noncurrent deferred income taxes” decreased by $21.
     Upon adoption, no significant asset retirement obligations associated with any legal obligations to retire refining, marketing and transportation (downstream) and chemical long-lived assets generally were recognized, as indeterminate settlement dates for the asset retirements prevented estimation of the fair value of the associated ARO. The company performs periodic reviews of its downstream and chemical long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.
     Other than the cumulative-effect net charge, the effect of the new accounting standard on net income in 2003 was not materially different from what the result would have been under FAS 19 accounting. Included in “Depreciation, depletion and amortization” were $52 related to the depreciation of the ARO asset and $132 related to the accretion of the ARO liability.
     In March 2005, the FASB issuedFASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — An Interpretation of FASB Statement No. 143,”(FIN 47), which was effective for the company on December 31, 2005. FIN 47 clarifies that the phrase “conditional asset retirement obligation,” as used in FAS 143, refers to a legal obligation to perform an asset retirement activity for which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the company. The following table illustrates whatobligation to perform the company’s net income before extraordinary items, net income and related per-share amountsasset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 also clarifies when an entity would have been ifsufficient information to reasonably estimate the provisionsfair value of FAS 143 had been applied retroactively:
         
  Year Ended December 31 
  2003  2002 
 
Pro forma net income before extraordinary items $7,4301 $1,1372
Earnings per share – basic3
 $3.57  $0.53 
Earnings per share – diluted3
 $3.57  $0.53 
Pro forma net income $7,4301 $1,1372
Earnings per share – basic4
 $3.57  $0.53 
Earnings per share – diluted4
 $3.57  $0.53 
 
1
Excludes cumulative-effect charge of $200 ($0.09 per basic and diluted share) for the adoption of FAS 143.
2
Includes benefit of $5 that represents the reversal of FAS 19 depreciation related to abandonment offset partially by pro forma expenses for the depreciation and accretion of the ARO asset and liability, net of tax. There is ade minimiseffect to net income per basic or diluted share.
3
Reported net income before extraordinary items was also $3.57 per basic and diluted
shares for 2003 and $0.53 per basic and diluted shares for 2002.
4
Reported net income was $3.48 per basic and diluted shares for 2003 and $0.53 per basic and diluted shares for 2002.

     Prior to the implementation of FAS 143,an asset retirement obligation. In adopting FIN 47, the company had recorded a provisiondid not recognize any additional liabilities for abandonment that was partconditional retirement obligations due to an inability to reasonably estimate the fair value of “Accumulated depreciation, depletion and amortization.” Upon implementationthose obligations because of FAS 143, the provision for abandonment was reversed and ARO liability was recorded. The amount of the abandonment reserve at the end of 2002 was $2,263. The 2002 pro-forma ARO liability at January 1 and December 31 was $2,792 and $2,797, respectively.their indeterminate settlement dates.

     The following table indicates the changes to the company’s before-tax asset retirement obligations in 2005, 2004 and 2003:
                
 2004 2003  2005 2004 2003 
       
Balance at January 1 $2,856   $2,797* $ 2,878   $ 2,856 $ 2,797*
Liabilities assumed in the Unocal acquisition 1,216   – – 
Liabilities incurred 37   14  90   37 14 
Liabilities settled  (426)   (128)  (172)   (426)  (128)
Accretion expense 93   132  187   93 132 
Revisions in estimated cash flows 318   41  105   318 41 
       
Balance at December 31 $2,878   $2,856  $4,304   $2,878 $2,856 
      
  
**Includes the cumulative effect of the accounting change.


FS-60

NOTE 26.25.
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 ChevronTexacoChevron stock units by

certain officers and employees of the company and the company’s share of stock transactions of affiliates, which, under the applicable accounting rules, may be recorded directly to the company’s retained earnings instead of net income. Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock



FS-54

4NOTE 26.EARNINGS PER SHARE – Continued

options awarded under the company’s stock option programs (see Note 23,22, “Stock Options” and Other Share-Based Compensation” beginning on page FS-50)FS-54). The following table sets forth the computation of basic and diluted EPS:

                    
 Year ended December 31  Year ended December 31 
 2004 2003 2002  2005 2004 2003 
       
BASIC EPS CALCULATION
      
Income from continuing operations $13,034   $7,382 $1,102  $14,099   $13,034 $7,382 
Add: Dividend equivalents paid on stock units 3   2 3  2   3 2 
Add: Affiliated stock transaction recorded to retained earnings1
 –   170 –  –   – 170 
       
Income from continuing operations available to common stockholders $13,037   $7,554 $1,105  $14,101   $13,037 $7,554 
Income from discontinued operations 294   44 30  –   294 44 
Cumulative effect of changes in accounting principle2
 –    (196) –  –   –  (196)
       
Net income available to common stockholders – Basic $13,331   $7,402 $1,135  $14,101   $13,331 $7,402 
       
Weighted average number of common shares outstanding3
 2,114   2,123 2,121 
Weighted-average number of common shares outstanding3
 2,143   2,114 2,123 
Add: Deferred awards held as stock units 2   2 2  1   2 2 
       
Total weighted average number of common share outstanding 2,116   2,125 2,123 
Total weighted-average number of common shares outstanding 2,144   2,116 2,125 
       
Per-Share of Common Stock      
Income from continuing operations available to common stockholders $6.16   $3.55 $0.52  $6.58   $6.16 $3.55 
Income from discontinued operations 0.14   0.02 0.01  –   0.14 0.02 
Cumulative effect of changes in accounting principle –    (0.09) –  –   –  (0.09)
       
Net income – Basic $6.30   $3.48 $0.53  $6.58   $6.30 $3.48 
       
      
DILUTED EPS CALCULATION
      
Income from continuing operations $13,034   $7,382 $1,102  $14,099   $13,034 $7,382 
Add: Dividend equivalents paid on stock units 3   2 3  2   3 2 
Add: Affiliated stock transaction recorded to retained earnings1
 –   170 –  –   – 170 
Add: Dilutive effects of employee stock-based awards 1   2 2  2   1 2 
       
Income from continuing operations available to common stockholders $13,038   $7,556 $1,107  $14,103   $13,038 $7,556 
Income from discontinued operations 294   44 30  –   294 44 
Cumulative effect of changes in accounting principle2
 –    (196) –  –   –  (196)
       
Net income available to common stockholders – Diluted $13,332   $7,404 $1,137  $14,103   $13,332 $7,404 
       
Weighted average number of common shares outstanding3
 2,114   2,123 2,121 
Weighted-average number of common shares outstanding3
 2,143   2,114 2,123 
Add: Deferred awards held as stock units 2   2 2  1   2 2 
Add: Dilutive effect of employee stock-based awards 6   2 3  11   6 2 
       
Total weighted average number of common share outstanding 2,122   2,127 2,126 
Total weighted-average number of common shares outstanding 2,155   2,122 2,127 
       
Per-Share of Common Stock      
Income from continuing operations available to common stockholders $6.14   $3.55 $0.52  $6.54   $6.14 $3.55 
Income from discontinued operations 0.14   0.02 0.01  –   0.14 0.02 
Cumulative effect of changes in accounting principle –    (0.09) –  –   –  (0.09)
       
Net income – Diluted $6.28   $3.48 $0.53  $6.54   $6.28 $3.48 
     
  
1
2003 amount is the company’s share of a capital stock transaction of its Dynegy affiliate, which, under the applicable accounting rules, was recorded directly to retained earnings.
  
2
Includes a net loss of $200 for the adoption of FAS 143 and a net gain of $4 for the company’s share of Dynegy’s cumulative effect of adoption of EITF 02-3.
  
3
Share amounts in all periodperiods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.

FS-55FS-61

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

NOTE 26.
COMMON STOCK SPLIT

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

NOTE 27.
OTHER FINANCIAL INFORMATION

Net income in 2004 included gains of approximately $1.2 billion relating to the sale of nonstrategic upstream properties.
     Other financial information is as follows:
              
  Year ended December 31 
   2005    2004   2003 
    
Total financing interest and debt costs $542   $450  $549 
Less: Capitalized interest  60    44   75 
      
Interest and debt expense $482   $406  $474 
    
Research and development expenses $316   $242  $228 
Foreign currency effects* $(61)  $(81) $(404)
    
*Includes $(2), $(13) and $(96) in 2005, 2004 and 2003, respectively, for the company’s share of equity affiliates’ foreign currency effects.
     The excess of market value over the carrying value of inventories for which the LIFO method is used was $4,846, $3,036 and $2,106 at December 31, 2005, 2004 and 2003, respectively. Market value is generally based on average acquisition costs for the year. LIFO profits of $34, $36 and $82 were included in net income for the years 2005, 2004 and 2003, respectively.



FS-62

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FS-56FS-63

FIVE-YEAR FINANCIAL SUMMARY

  
Five-Year Financial SummaryFIVE-YEAR FINANCIAL SUMMARY
Unaudited
Unaudited
                                    
Millions of dollars, except per-share amounts 2004 2003 2002 2001 2000  2005 2004 2003 2002 2001 
      
COMBINED STATEMENT OF INCOME DATA
      
REVENUES AND OTHER INCOME
      
Total sales and other operating revenues $150,865   $119,575 $98,340 $103,951 $116,619  $193,641   $150,865 $119,575 $98,340 $103,951 
Income from equity affiliates and other income 4,435   1,702 197 1,751 1,917  4,559   4,435 1,702 197 1,751 
       
TOTAL REVENUES AND OTHER INCOME
 155,300   121,277 98,537 105,702 118,536  198,200   155,300 121,277 98,537 105,702 
TOTAL COSTS AND OTHER DEDUCTIONS
 134,749   108,601 94,437 97,517 104,661  173,003   134,749 108,601 94,437 97,517 
       
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
 20,551   12,676 4,100 8,185 13,875  25,197   20,551 12,676 4,100 8,185 
INCOME TAX EXPENSE
 7,517   5,294 2,998 4,310 6,237  11,098   7,517 5,294 2,998 4,310 
       
NET INCOME FROM CONTINUING OPERATIONS
 13,034   7,382 1,102 3,875 7,638 
NET INCOME FROM DISCONTINUED OPERATIONS
 294   44 30 56 89 
INCOME FROM CONTINUING OPERATIONS
 14,099   13,034 7,382 1,102 3,875 
INCOME FROM DISCONTINUED OPERATIONS
 –   294 44 30 56 
       
NET INCOME BEFORE EXTRAORDINARY ITEM AND
   
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
 13,328   7,426 1,132 3,931 7,727 
INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
 14,099   13,328 7,426 1,132 3,931 
Extraordinary loss, net of tax –   – –  (643) –  –   – – –  (643)
Cumulative effect of changes in accounting principles –    (196) – – –  –   –  (196) – – 
       
NET INCOME
 $13,328   $7,230 $1,132 $3,288 $7,727  $14,099   $13,328 $7,230 $1,132 $3,288 
       
PER SHARE OF COMMON STOCK1
      
INCOME FROM CONTINUING OPERATIONS2
      
– Basic $6.16   $3.55 $0.52 $1.82 $3.58  $6.58   $6.16 $3.55 $0.52 $1.82 
– Diluted $6.14   $3.55 $0.52 $1.82 $3.57  $6.54   $6.14 $3.55 $0.52 $1.82 
INCOME FROM DISCONTINUED OPERATIONS
      
– Basic $0.14   $0.02 $0.01 $0.03 $0.04  $–   $0.14 $0.02 $0.01 $0.03 
– Diluted $0.14   $0.02 $0.01 $0.03 $0.04  $–   $0.14 $0.02 $0.01 $0.03 
EXTRAORDINARY ITEM
      
– Basic $–   $– $– $(0.30) $–  $–   $– $– $– $(0.30)
– Diluted $–   $– $– $(0.30) $–  $–   $– $– $– $(0.30)
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
      
– Basic $–   $(0.09) $– $– $–  $–   $– $(0.09) $– $– 
– Diluted $–   $(0.09) $– $– $–  $–   $– $(0.09) $– $– 
NET INCOME2
      
– Basic $6.30   $3.48 $0.53 $1.55 $3.62  $6.58   $6.30 $3.48 $0.53 $1.55 
– Diluted $6.28   $3.48 $0.53 $1.55 $3.61  $6.54   $6.28 $3.48 $0.53 $1.55 
       
CASH DIVIDENDS PER SHARE3
 $1.53   $1.43 $1.40 $1.33 $1.30 
CASH DIVIDENDS PER SHARE
 $1.75   $1.53 $1.43 $1.40 $1.33 
       
COMBINED BALANCE SHEET DATA (AT DECEMBER 31)
      
Current assets $28,503   $19,426 $17,776 $18,327 $17,913  $34,336   $28,503 $19,426 $17,776 $18,327 
Noncurrent assets 64,705   62,044 59,583 59,245 59,708  91,497   64,705 62,044 59,583 59,245 
       
TOTAL ASSETS
 93,208   81,470 77,359 77,572 77,621  125,833   93,208 81,470 77,359 77,572 
       
Short-term debt 816   1,703 5,358 8,429 3,094  739   816 1,703 5,358 8,429 
Other current liabilities 17,979   14,408 14,518 12,225 13,567  24,272   17,979 14,408 14,518 12,225 
Long-term debt and capital lease obligations 10,456   10,894 10,911 8,989 12,821  12,131   10,456 10,894 10,911 8,989 
Other noncurrent liabilities 18,727   18,170 14,968 13,971 14,770  26,015   18,727 18,170 14,968 13,971 
       
TOTAL LIABILITIES
 47,978   45,175 45,755 43,614 44,252  63,157   47,978 45,175 45,755 43,614 
       
STOCKHOLDERS’ EQUITY
 $45,230   $36,295 $31,604 $33,958 $33,369  $62,676   $45,230 $36,295 $31,604 $33,958 
     
  
1
Per-share amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
  
2
The amount in 2003 includes a benefit of $0.08 for the company’s share of a capital stock transaction of its Dynegy Inc. affiliate, which, under the applicable accounting rules, was recorded directly to retained earnings and not included in net income for the period.

FS-64

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

  
3
Chevron Corporation dividend pre-merger.
 
Supplemental Information on Oil and Gas Producing Activities
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
Unaudited

In accordance with Statement of FAS 69, “Disclosures“Disclosures About Oil and Gas Producing Activities,” this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized
costs; and results of operations. Tables V through VII present information on the company’s
estimated net proved reserve quantities; standardized measure of estimated discounted future net cash flows related to proved reserves;


FS-57

Supplemental Information on Oil and Gas Producing Activities –Continued

and changes in estimated discounted future net cash flows. The Africa geographic area includes activities principally in Nigeria, Angola, Chad, Republic of the Congo and the Democratic Republic of the Congo (sold in 2004).Congo. The Asia-Pacific geographic area includes activities principally in Australia, Azerbaijan, Bangladesh, China, Kazakhstan, Myanmar, the


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

                                                 
  Consolidated Companies    
  United States  International        
      Gulf of      Total      Asia-          Total      Affiliated Companies 
Millions of dollars Calif.  Mexico  Other  U.S.  Africa  Pacific  Indonesia  Other  Int’l.  Total  TCO  Hamaca 
     
YEAR ENDED DEC. 31, 2005
                                                
Exploration                                                
Wells $–  $452  $24  $476  $105  $38  $9  $201  $353  $829  $–  $– 
Geological and geophysical  –   67   –   67   96   28   10   68   202   269   –   – 
Rentals and other  –   93   8   101   24   58   12   72   166   267   –   – 
 
Total exploration  –   612   32   644   225   124   31   341   721   1,365   –   – 
 
Property acquisitions                                                
Proved – Unocal2,3
  –   1,608   2,388   3,996   30   6,609   637   1,790   9,066   13,062   –   – 
Proved – Other2
  –   6 �� 10   16   2   2   –   12   16   32   –   – 
Unproved – Unocal  –   819   295   1,114   11   2,209   821   38   3,079   4,193   –   – 
Unproved – Other  –   17   6   23   67   –   –   28   95   118   –   – 
 
Total property acquisitions  –   2,450   2,699   5,149   110   8,820   1,458   1,868   12,256   17,405   –   – 
 
Development4
  494   639   596   1,729   1,871   1,026   325   713   3,935   5,664   767   43 
ARO asset  13   41   5   59   21   62   57   13   153   212   –   – 
 
TOTAL COSTS INCURRED
 $507  $3,742  $3,332  $7,581  $2,227  $10,032  $1,871  $2,935  $17,065  $24,646  $767  $43 
 
YEAR ENDED DEC. 31, 2004
                                                
Exploration                                                
Wells $–  $388  $–  $388  $116  $25  $2  $127  $270  $658  $–  $– 
Geological and geophysical  –   47   2   49   103   10   12   46   171   220   –   – 
Rentals and other  –   43   3   46   52   47   1   53   153   199   –   – 
 
Total exploration  –   478   5   483   271   82   15   226   594   1,077   –   – 
 
Property acquisitions                                                
Proved2
  –   6   1   7   111   16   –   4   131   138   –   – 
Unproved  –   29   –   29   82   –   –   5   87   116   –   – 
 
Total property acquisitions  –   35   1   36   193   16   –   9   218   254   –   – 
 
Development4
  412   457   372   1,241   1,047   567   245   542   2,401   3,642   896   208 
ARO asset  1   9   3   13   10   53   158   85   306   319   –   – 
 
TOTAL COSTS INCURRED
 $413  $979  $381  $1,773  $1,521  $718  $418  $862  $3,519  $5,292  $896  $208 
 
YEAR ENDED DEC. 31, 2003
                                                
Exploration                                                
Wells $–  $415  $9  $424  $116  $43  $2  $72  $233  $657  $–  $– 
Geological and geophysical  –   16   23   39   75   9   5   30   119   158   –   – 
Rentals and other  –   64   (20)  44   12   58   –   46   116   160   –   – 
 
Total exploration  –   495   12   507   203   110   7   148   468   975   –   – 
 
Property acquisitions                                                
Proved2
  –   15   3   18   –   20   –   7   27   45   –   – 
Unproved  –   30   3   33   51   6   –   14   71   104   –   – 
 
Total property acquisitions  –   45   6   51   51   26   –   21   98   149   –   – 
 
Development  264   434   350   1,048   974   605   363   461   2,403   3,451   551   199 
 
TOTAL COSTS INCURRED
 $264  $974  $368  $1,606  $1,228  $741  $370  $630  $2,969  $4,575  $551  $199 
 
1
Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. See Note 24, “Asset Retirement Obligations,” beginning on page FS-59.
2
Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired through property exchanges.
3
Included in proved property acquisitions for Unocal are $845 of ARO assets, composed of: Gulf of Mexico $115; Other U.S. $271; Africa $9; Asia-Pacific $366; Indonesia $25; Other International $59.
4
Includes $160 and $63 costs incurred prior to assignment of proved reserves in 2005 and 2004, respectively.

FS-65

Supplemental Information on Oil and Gas Producing Activities —Continued

Partitioned Neutral Zone between Kuwait and Saudi Arabia, Papua New Guinea (sold in 2003), the Philippines, and Thailand. The international “Other” geographic category includes activities in the United Kingdom,Argentina, Brazil, Canada, Colombia, Denmark, Germany, the Netherlands,
Norway, Trinidad and Tobago, Colombia, Venezuela, Brazil, Argentina,the United Kingdom, and other countries. Amounts shown for affiliated companies are ChevronTexaco’s Chevron’s
50 percent equity share of TCO, an exploration and production partnership operating in the Republic of Kazakhstan, and a 30 percent equity share of Hamaca, an exploration and production partnership operating in Venezuela.
     Amounts in the tables exclude the cumulative effect adjustment for the adoption of FAS 143, “Asset“Asset Retirement Obligations.Obligations,” Refer todiscussed in Note 2524, beginning on page FS-53.FS-59.


TABLE I – COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS AND DEVELOPMENT1
                                                 
  Consolidated Companies    
  United States  International        
      Gulf of      Total      Asia-          Total      Affiliated Companies 
Millions of dollars Calif.  Mexico  Other  U.S.  Africa  Pacific  Indonesia  Other  Int’l.  Total  TCO  Hamaca 
       
YEAR ENDED DEC. 31, 2004
                                                
Exploration                                                
Wells $–  $388  $–  $388  $116  $25  $2  $127  $270  $658  $–  $– 
Geological and geophysical  –   47   2   49   103   10   12   46   171   220   –   – 
Rentals and other  –   43   3   46   52   47   1   53   153   199   –   – 
 
Total exploration  –   478   5   483   271   82   15   226   594   1,077   –   – 
 
Property acquisitions                                                
Proved2
  –   6   1   7   111   16   –   4   131   138   –   – 
Unproved  –   29   –   29   82   –   –   5   87   116   –   – 
 
Total property acquisitions  –   35   1   36   193   16   –   9   218   254   –   – 
 
Development3
  412   457   372   1,241   1,047   567   245   542   2,401   3,642   896   208 
ARO Asset  1   9   3   13   10   53   158   85   306   319   –   – 
 
TOTAL COSTS INCURRED
 $413  $979  $381  $1,773  $1,521  $718  $418  $862  $3,519  $5,292  $896  $208 
 
YEAR ENDED DEC. 31, 2003
                                                
Exploration                                                
Wells $–  $415  $9  $424  $116  $43  $2  $72  $233  $657  $–  $– 
Geological and geophysical  –   16   23   39   75   9   5   30   119   158   –   – 
Rentals and other  –   64   (20)  44   12   58   –   46   116   160   –   – 
 
Total exploration  –   495   12   507   203   110   7   148   468   975   –   – 
 
Property acquisitions                                                
Proved2
  –   15   3   18   –   20   –   7   27   45   –   – 
Unproved  –   30   3   33   51   6   –   14   71   104   –   – 
 
Total property acquisitions  –   45   6   51   51   26   –   21   98   149   –   – 
 
Development  264   434   350   1,048   974   605   363   461   2,403   3,451   551   199 
 
TOTAL COSTS INCURRED
 $264  $974  $368  $1,606  $1,228  $741  $370  $630  $2,969  $4,575  $551  $199 
 
YEAR ENDED DEC. 31, 2002
                                                
Exploration                                                
Wells $25  $413  $39  $477  $131  $32  $16  $92  $271  $748  $–  $– 
Geological and geophysical  –   86   9   95   69   30   13   53   165   260   –   – 
Rentals and other  –   30   5   35   29   37   1   43   110   145   –   – 
 
Total exploration  25   529   53   607   229   99   30   188   546   1,153   –   – 
 
Property acquisitions                                                
Proved2
  –   96   10   106   –   –   –   –   –   106   –   – 
Unproved  –   48   3   51   6   2   –   1   9   60   –   – 
 
Total property acquisitions  –   144   13   157   6   2   –   1   9   166   –   – 
 
Development  221   475   395   1,091   661   593   424   926   2,604   3,695   447   353 
 
TOTAL COSTS INCURRED
 $246  $1,148  $461  $1,855  $896  $694  $454  $1,115  $3,159  $5,014  $447  $353 
 
1
Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. See Note 25, FAS 143,“Asset Retirement Obligations,”on page FS-53.
2
Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired through property exchanges.
3
Includes $63 costs incurred prior to assignment of proved reserves.

FS-58

TABLE II – CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES1
                                                  
 Consolidated Companies    Consolidated Companies    
 United States International    United States  International    
 Gulf of Total Asia- Total Affiliated Companies  Gulf of Total Asia- Total Affiliated Companies 
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int'l. Total TCO Hamaca  Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Hamaca 
    
AT DEC. 31, 2005
 
Unproved properties $769 $1,077 $397 $2,243 $407 $2,287 $645 $983 $4,322 $6,565 $108 $– 
Proved properties and related producing assets 9,530 17,871 11,103 38,504 8,169 14,308 4,441 9,259 36,177 74,681 2,259 1,212 
Support equipment 204 193 230 627 715 426 3,124 356 4,621 5,248 549 – 
Deferred exploratory wells – 284 5 289 245 154 173 248 820 1,109 – – 
Other uncompleted projects 149 782 209 1,140 2,878 790 427 946 5,041 6,181 2,332 – 
ARO asset2
 16 412 364 792 235 620 265 368 1,488 2,280 5 1 
GROSS CAP. COSTS
 10,668 20,619 12,308 43,595 12,649 18,585 9,075 12,160 52,469 96,064 5,253 1,213 
Unproved properties valuation 736 90 22 848 162 69 – 318 549 1,397 17 – 
Proved producing properties – 
Depreciation and depletion 6,813 13,866 5,943 26,622 4,132 3,915 2,895 5,533 16,475 43,097 455 90 
Support equipment depreciation 140 119 149 408 317 88 1,824 222 2,451 2,859 213 – 
ARO asset depreciation2
 5 201 106 312 134 101 66 187 488 800 5 – 
Accumulated provisions 7,694 14,276 6,220 28,190 4,745 4,173 4,785 6,260 19,963 48,153 690 90 
NET CAPITALIZED COSTS
 $2,974 $6,343 $6,088 $15,405 $7,904 $14,412 $4,290 $5,900 $32,506 $47,911 $4,563 $1,123 
    
AT DEC. 31, 2004
  
Unproved properties $769 $380 $109 $1,258 $322 $211 $– $970 $1,503 $2,761 $108 $–  $769 $380 $109 $1,258 $322 $211 $– $970 $1,503 $2,761 $108 $– 
Proved properties and related producing assets 9,170 16,610 8,660 34,440 7,188 7,485 3,643 8,961 27,277 61,717 2,163 963  9,170 16,610 8,660 34,440 7,188 7,485 3,643 8,961 27,277 61,717 2,163 963 
Support equipment 211 175 208 594 513 127 3,030 361 4,031 4,625 496 –  211 175 208 594 513 127 3,030 361 4,031 4,625 496 – 
Deferred exploratory wells – 225 – 225 213 81 – 152 446 671 – –  – 225 – 225 213 81 – 152 446 671 – – 
Other uncompleted projects 91 400 169 660 2,050 605 351 391 3,397 4,057 1,749 149  91 400 169 660 2,050 605 351 391 3,397 4,057 1,749 149 
ARO asset2
 28 204 70 302 206 113 181 292 792 1,094 20 –  28 204 70 302 206 113 181 292 792 1,094 20 – 
GROSS CAP. COSTS
 10,269 17,994 9,216 37,479 10,492 8,622 7,205 11,127 37,446 74,925 4,536 1,112  10,269 17,994 9,216 37,479 10,492 8,622 7,205 11,127 37,446 74,925 4,536 1,112 
Unproved properties valuation 734 111 27 872 118 67 – 294 479 1,351 15 –  734 111 27 872 118 67 – 294 479 1,351 15 – 
Proved producing properties – Depreciation and depletion 6,694 13,562 5,617 25,873 3,753 3,122 2,396 4,933 14,204 40,077 423 43 
Proved producing properties – 
Depreciation and depletion 6,694 13,562 5,617 25,873 3,753 3,122 2,396 4,933 14,204 40,077 423 43 
Support equipment depreciation 148 107 139 394 268 60 1,802 206 2,336 2,730 190 –  148 107 139 394 268 60 1,802 206 2,336 2,730 190 – 
ARO asset depreciation2
 24 174 64 262 128 49 36 148 361 623 5 –  24 174 64 262 128 49 36 148 361 623 5 – 
Accumulated provisions 7,600 13,954 5,847 27,401 4,267 3,298 4,234 5,581 17,380 44,781�� 633 43  7,600 13,954 5,847 27,401 4,267 3,298 4,234 5,581 17,380 44,781 633 43 
NET CAPITALIZED COSTS
 $2,669 $4,040 $3,369 $10,078 $6,225 $5,324 $2,971 $5,546 $20,066 $30,144 $3,903 $1,069  $2,669 $4,040 $3,369 $10,078 $6,225 $5,324 $2,971 $5,546 $20,066 $30,144 $3,903 $1,069 
AT DEC. 31, 20033
 
Unproved properties $769 $416 $131 $1,316 $290 $214 $– $1,048 $1,552 $2,868 $108 $– 
Proved properties and related producing assets 8,785 18,069 10,749 37,603 6,474 6,288 3,097 10,469 26,328 63,931 2,091 356 
Support equipment 200 200 277 677 519 100 3,016 374 4,009 4,686 425 – 
Deferred exploratory wells – 126 1 127 233 67 2 120 422 549 – – 
Other uncompleted projects 76 280 152 508 1,894 1,502 715 334 4,445 4,953 1,011 661 
ARO asset2
 25 227 83 335 207 60 23 236 526 861 20 1 
GROSS CAP. COSTS
 9,855 19,318 11,393 40,566 9,617 8,231 6,853 12,581 37,282 77,848 3,655 1,018 
Unproved properties valuation 731 138 43 912 101 59 1 310 471 1,383 12 – 
Proved producing properties – depreciation and depletion 6,473 14,450 6,894 27,817 3,656 2,793 2,022 6,015 14,486 42,303 354 24 
Support equipment depreciation 141 133 180 454 237 68 1,784 200 2,289 2,743 160 – 
ARO asset depreciation2
 23 186 79 288 133 36 19 148 336 624 4 – 
Accumulated provisions 7,368 14,907 7,196 29,471 4,127 2,956 3,826 6,673 17,582 47,053 530 24 
NET CAPITALIZED COSTS
 $2,487 $4,411 $4,197 $11,095 $5,490 $5,275 $3,027 $5,908 $19,700 $30,795 $3,125 $994 
  
1
Includes assets held for sale.
  
2
See Note 25, FAS 143,“Asset24, “Asset Retirement Obligations,” beginning on page FS-53
3
2003 and 2002 reclassified to conform to 2004 presentation.FS-59.

FS-59FS-66

  
Supplemental Information on Oil and Gas Producing Activities
TABLE II – CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES1 — Continued

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

                                                 
 Consolidated Companies    Consolidated Companies    
 United States International    United States  International    
 Gulf of Total Asia- Total Affiliated Companies  Gulf of Total Asia- Total Affiliated Companies 
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int'l. Total TCO Hamaca  Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Hamaca 
         
AT DEC. 31, 20022
 
AT DEC. 31, 20032
 
Unproved properties $770 $421 $171 $1,362 $330 $237 $22 $1,134 $1,723 $3,085 $108 $–  $769 $416 $131 $1,316 $290 $214 $– $1,048 $1,552 $2,868 $108 $– 
Proved properties and related producing assets 8,584 17,657 11,200 37,441 6,037 6,356 3,432 10,185 26,010 63,451 1,975 147  8,785 18,069 10,749 37,603 6,474 6,288 3,097 10,469 26,328 63,931 2,091 356 
Support equipment 187 189 398 774 447 190 3,004 377 4,018 4,792 338 –  200 200 277 677 519 100 3,016 374 4,009 4,686 425 – 
Deferred exploratory wells – 101 1 102 167 103 – 106 376 478 – –  – 126 1 127 233 67 2 120 422 549 – – 
Other uncompleted projects 97 209 200 506 1,380 1,179 474 264 3,297 3,803 676 693  76 280 152 508 1,894 1,502 715 334 4,445 4,953 1,011 661 
ARO asset3
 25 227 83 335 207 60 23 236 526 861 20 1 
GROSS CAP. COSTS
 9,638 18,577 11,970 40,185 8,361 8,065 6,932 12,066 35,424 75,609 3,097 840  9,855 19,318 11,393 40,566 9,617 8,231 6,853 12,581 37,282 77,848 3,655 1,018 
Unproved properties valuation 732 154 75 961 80 67 23 277 447 1,408 9 –  731 138 43 912 101 59 1 310 471 1,383 12 – 
Proved producing properties – depreciation and depletion 6,295 13,722 7,098 27,115 3,275 2,608 2,143 5,358 13,384 40,499 285 9 
Future abandonment and restoration 150 363 486 999 508 147 157 392 1,204 2,203 24 – 
Support equipment depreciation 130 123 304 557 289 100 1,764 223 2,376 2,933 138 – 
Proved producing properties – 
Depreciation and depletion 6,473 14,450 6,894 27,817 3,656 2,793 2,022 6,015 14,486 42,303 354 24 
Future equipment depreciation 141 133 180 454 237 68 1,784 200 2,289 2,743 160 – 
ARO asset depreciation3
 23 186 79 288 133 36 19 148 336 624 4 – 
Accumulated provisions 7,307 14,362 7,963 29,632 4,152 2,922 4,087 6,250 17,411 47,043 456 9  7,368 14,907 7,196 29,471 4,127 2,956 3,826 6,673 17,582 47,053 530 24 
NET CAPITALIZED COSTS
 $2,331 $4,215 $4,007 $10,553 $4,209 $5,143 $2,845 $5,816 $18,013 $28,566 $2,641 $831  $2,487 $4,411 $4,197 $11,095 $5,490 $5,275 $3,027 $5,908 $19,700 $30,795 $3,125 $994 
  
1
Includes assets held for sale.
  
2
2003 and 2002 reclassified to conform to 20042005 presentation.
3
See Note 24, “Asset Retirement Obligations,” beginning on page FS-59.

FS-60FS-67

Supplemental Information on Oil and Gas Producing Activities –Continued

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 2005, 2004 2003 and 20022003 are shown in the following table. Net income from exploration and production activities as reported on page FS-36FS-41 reflects income taxes computed on an effective rate basis.
In accordance with FAS 69,
income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the net income amounts on page FS-36.FS-41.


                                                 
 Consolidated Companies    Consolidated Companies    
 United States International    United States  International    
 Gulf of Total Asia- Total Affiliated Companies  Gulf of Total Asia- Total Affiliated Companies 
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Hamaca  Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Hamaca 
    
YEAR ENDED DEC. 31, 2005
 
Revenues from net production 
Sales $337 $1,576 $3,174 $5,087 $2,142 $2,941 $539 $2,668 $8,290 $13,377 $2,307 $666 
Transfers 3,497 2,127 1,395 7,019 3,615 3,179 1,986 2,607 11,387 18,406 – – 
Total 3,834 3,703 4,569 12,106 5,757 6,120 2,525 5,275 19,677 31,783 2,307 666 
Production expenses excluding taxes  (916)  (638)  (777)  (2,331)  (558)  (570)  (660)  (596)  (2,384)  (4,715)  (152)  (82)
Taxes other than on income  (65)  (41)  (384)  (490)  (48)  (189)  (1)  (195)  (433)  (923)  (27) – 
Proved producing properties:
Depreciation and depletion  (253)  (936)  (520)  (1,709)  (414)  (852)  (550)  (672)  (2,488)  (4,197)  (83)  (46)
Accretion expense2
  (13)  (35)  (46)  (94)  (22)  (20)  (15)  (25)  (82)  (176)  (1) – 
Exploration expenses –  (307)  (13)  (320)  (117)  (90)  (26)  (190)  (423)  (743) – – 
Unproved properties valuation  (3)  (32)  (4)  (39)  (50)  (8) –  (24)  (82)  (121) – – 
Other income (expense)3
 2  (354)  (140)  (492)  (243)  (182) 182 280 37  (455)  (9) 8 
Results before income taxes 2,586 1,360 2,685 6,631 4,305 4,209 1,455 3,853 13,822 20,453 2,035 546 
Income tax expense  (913)  (482)  (953)  (2,348)  (3,430)  (2,264)  (644)  (1,938)  (8,276)  (10,624)  (611)  (186)
RESULTS OF PRODUCING OPERATIONS
 $1,673 $878 $1,732 $4,283 $875 $1,945 $811 $1,915 $5,546 $9,829 $1,424 $360 
    
YEAR ENDED DEC. 31, 2004
  
Revenues from net production  
Sales $251 $1,925 $2,163 $4,339 $1,321 $1,191 $256 $2,481 $5,249 $9,588 $1,619 $205  $251 $1,925 $2,163 $4,339 $1,321 $1,191 $256 $2,481 $5,249 $9,588 $1,619 $205 
Transfers 2,651 1,768 1,224 5,643 2,645 2,265 1,613 1,903 8,426 14,069 – –  2,651 1,768 1,224 5,643 2,645 2,265 1,613 1,903 8,426 14,069 – – 
Total 2,902 3,693 3,387 9,982 3,966 3,456 1,869 4,384 13,675 23,657 1,619 205  2,902 3,693 3,387 9,982 3,966 3,456 1,869 4,384 13,675 23,657 1,619 205 
Production expenses excluding taxes  (710)  (547)  (697)  (1,954)  (574)  (431)  (591)  (544)  (2,140)  (4,094)  (143)  (53)  (710)  (547)  (697)  (1,954)  (574)  (431)  (591)  (544)  (2,140)  (4,094)  (143)  (53)
Taxes other than on income  (57)  (45)  (321)  (423)  (24)  (138)  (1)  (134)  (297)  (720)  (26) –   (57)  (45)  (321)  (423)  (24)  (138)  (1)  (134)  (297)  (720)  (26) – 
Proved producing properties:  
depreciation and depletion  (232)  (774)  (384)  (1,390)  (367)  (401)  (393)  (798)  (1,959)  (3,349)  (104)  (4)
Depreciation and depletion  (232)  (774)  (384)  (1,390)  (367)  (401)  (393)  (798)  (1,959)  (3,349)  (104)  (4)
Accretion expense2
  (12)  (25)  (19)  (56)  (22)  (8)  (13) 11  (32)  (88)  (2) –   (12)  (25)  (19)  (56)  (22)  (8)  (13) 11  (32)  (88)  (2) – 
Exploration expenses –  (227)  (6)  (233)  (235)  (69)  (17)  (144)  (465)  (698) – –  –  (227)  (6)  (233)  (235)  (69)  (17)  (144)  (465)  (698) – – 
Unproved properties valuation  (3)  (29)  (4)  (36)  (23)  (8) –  (25)  (56)  (92) – –   (3)  (29)  (4)  (36)  (23)  (8) –  (25)  (56)  (92) – – 
Other (expense) income3
 14 24 474 512 49 10 12 1,028 1,099 1,611  (7)  (58)
Other income (expense)3
 14 24 474 512 49 10 12 1,028 1,099 1,611  (7)  (58)
Results before income taxes 1,902 2,070 2,430 6,402 2,770 2,411 866 3,778 9,825 16,227 1,337 90  1,902 2,070 2,430 6,402 2,770 2,411 866 3,778 9,825 16,227 1,337 90 
Income tax expense  (703)  (765)  (898)  (2,366)  (2,036)  (1,395)  (371)  (1,759)  (5,561)  (7,927)  (401) –   (703)  (765)  (898)  (2,366)  (2,036)  (1,395)  (371)  (1,759)  (5,561)  (7,927)  (401) – 
RESULTS OF PRODUCING OPERATIONS
 $1,199 $1,305 $1,532 $4,036 $734 $1,016 $495 $2,019 $4,264 $8,300 $936 $90  $1,199 $1,305 $1,532 $4,036 $734 $1,016 $495 $2,019 $4,264 $8,300 $936 $90 
YEAR ENDED DEC. 31, 20034
 
Revenues from net production 
Sales $261 $2,197 $2,049 $4,507 $1,339 $1,442 $55 $2,556 $5,392 $9,899 $1,116 $104 
Transfers 2,085 1,740 1,096 4,921 1,835 1,738 1,566 1,356 6,495 11,416 – – 
Total 2,346 3,937 3,145 9,428 3,174 3,180 1,621 3,912 11,887 21,315 1,116 104 
Production expenses excluding taxes  (631)  (578)  (750)  (1,959)  (505)  (331)  (616)  (669)  (2,121)  (4,080)  (117)  (20)
Taxes other than on income  (28)  (48)  (280)  (356)  (22)  (126)  (1)  (100)  (249)  (605)  (29) – 
Proved producing properties: 
depreciation and depletion  (224)  (878)  (430)  (1,532)  (327)  (398)  (314)  (846)  (1,885)  (3,417)  (97)  (4)
Accretion expense2
  (12)  (37)  (20)  (69)  (20)  (5)  (8)  (26)  (59)  (128)  (2) – 
Exploration expenses  (2)  (168)  (23)  (193)  (123)  (130)  (8)  (117)  (378)  (571) – – 
Unproved properties valuation –  (16)  (4)  (20)  (20)  (9) –  (41)  (70)  (90) – – 
Other (expense) income3
  (18)  (104)  (51)  (173)  (173)  (342) 2  (175)  (688)  (861)  (4)  (35)
Results before income taxes 1,431 2,108 1,587 5,126 1,984 1,839 676 1,938 6,437 11,563 867 45 
Income tax expense  (528)  (777)  (585)  (1,890)  (1,410)  (1,158)  (289)  (831)  (3,688)  (5,578)  (260) – 
RESULTS OF PRODUCING OPERATIONS
 $903 $1,331 $1,002 $3,236 $574 $681 $387 $1,107 $2,749 $5,985 $607 $45 
  
1
The value of owned production consumed on lease as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
  
2
SeeRepresents accretion of ARO liability. Refer to Note 2524, “Asset Retirement Obligations,” beginning on page FS-53, FAS 143,“Asset Retirement Obligations.”FS-59.
  
3
Includes net sulfur income, foreign currency transaction gains and losses, certain significant impairment write-downs in 2004 and 2003, miscellaneous expenses, etc. Also includes net income from related oil and gas activities that do not have oil and gas reserves attributed to them (for example, net income from technical and operating service agreements) and items identified in the MD&AManagement’s Discussion and Analysis on pages FS-6FS-7 through FS-8.
4
2003 includes certain reclassifications to conform to 2004 presentation.FS-11. Does not include results for LNG-related activities.

FS-61FS-68

  
Supplemental Information on Oil and Gas Producing Activities
TABLE III – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES1 – Continued

TABLE III – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES1 – Continued

                                                
 Consolidated Companies    Consolidated Companies    
 United States International    United States  International    
 Gulf of Total Asia- Total Affiliated Companies  Gulf of Total Asia- Total Affiliated Companies 
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Hamaca  Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Hamaca 
         
YEAR ENDED DEC. 31, 20022
 
YEAR ENDED DEC. 31, 20032
 
Revenues from net production  
Sales $359 $1,302 $1,076 $2,737 $1,121 $1,181 $229 $2,080 $4,611 $7,348 $955 $44  $261 $2,197 $2,049 $4,507 $1,339 $1,442 $55 $2,556 $5,392 $9,899 $1,116 $104 
Transfers 1,621 1,611 1,193 4,425 1,663 1,560 1,530 1,202 5,955 10,380 – –  2,085 1,740 1,096 4,921 1,835 1,738 1,566 1,356 6,495 11,416 – – 
Total 1,980 2,913 2,269 7,162 2,784 2,741 1,759 3,282 10,566 17,728 955 44  2,346 3,937 3,145 9,428 3,174 3,180 1,621 3,912 11,887 21,315 1,116 104 
Production expenses excluding taxes  (570)  (630)  (782)  (1,982)  (415)  (330)  (680)  (606)  (2,031)  (4,013)  (130)  (4)  (631)  (578)  (750)  (1,959)  (505)  (331)  (616)  (669)  (2,121)  (4,080)  (117)  (20)
Taxes other than on income  (60)  (53)  (226)  (339)  (24)  (114) –  (77)  (215)  (554)  (36) –   (28)  (48)  (280)  (356)  (22)  (126)  (1)  (100)  (249)  (605)  (29) – 
Proved producing properties:  
depreciation and depletion  (250)  (844)  (389)  (1,483)  (314)  (345)  (315)  (654)  (1,628)  (3,111)  (86)  (5)
FAS 19 abandonment provision3
  (12)  (70)  (12)  (94)  (38)  (16) 3  (40)  (91)  (185)  (5) – 
Depreciation and depletion  (224)  (878)  (430)  (1,532)  (327)  (398)  (314)  (846)  (1,885)  (3,417)  (97)  (4)
Accretion Expense3
  (12)  (37)  (20)  (69)  (20)  (5)  (8)  (26)  (59)  (128)  (2) – 
Exploration expenses 1  (179)  (38)  (216)  (106)  (89)  (20)  (160)  (375)  (591) – –   (2)  (168)  (23)  (193)  (123)  (130)  (8)  (117)  (378)  (571) – – 
Unproved properties valuation  (2)  (24)  (9)  (35)  (14)  (9) –  (67)  (90)  (125) – –  –  (16)  (4)  (20)  (20)  (9) –  (41)  (70)  (90) – – 
Other (expense) income4
  (58)  (108)  (193)  (359)  (179)  (202)  (31) 59  (353)  (712)  (5)  (12)  (18)  (104)  (51)  (173)  (173)  (342) 2  (175)  (688)  (861)  (4)  (35)
Results before income taxes 1,029 1,005 620 2,654 1,694 1,636 716 1,737 5,783 8,437 693 23  1,431 2,108 1,587 5,126 1,984 1,839 676 1,938 6,437 11,563 867 45 
Income tax expense  (362)  (353)  (218)  (933)  (1,202)  (1,097)  (337)  (677)  (3,313)  (4,246)  (208) –   (528)  (777)  (585)  (1,890)  (1,410)  (1,158)  (289)  (831)  (3,688)  (5,578)  (260) – 
RESULTS OF PRODUCING OPERATIONS
 $667 $652 $402 $1,721 $492 $539 $379 $1,060 $2,470 $4,191 $485 $23  $903 $1,331 $1,002 $3,236 $574 $681 $387 $1,107 $2,749 ��$5,985 $607 $45 
  
1
The value of owned production consumed on lease as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
  
2
20022003 includes certain reclassifications to conform to 20042005 presentation.
  
3
SeeRepresents accretion of ARO liability. Refer to Note 2524, “Assets Retirement Obligation,” beginning on page FS-53, FAS 143,“Asset Retirement Obligations.”F5-59.
  
4
Includes net sulfur income, foreign currency transaction gains and losses, certain significant impairment write-downs, miscellaneous expenses, etc. Also includes net income from related oil and gas activities that do not have oil and gas reserves attributed to them (for example, net income from technical and operating service agreements) and items identified in the MD&AManagement’s Discussion and Analysis on pages FS-6FS-7 through FS-8.FS-11.

FS-69

Supplemental Information on Oil and Gas Producing Activities —Continued

TABLE IV – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES – UNIT PRICES AND COSTS1,21,2

                                                  
 Consolidated Companies    Consolidated Companies    
 United States International    United States  International    
 Gulf of Total Asia- Total Affiliated Companies  Gulf of Total Asia- Total Affiliated Companies 
 Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Hamaca  Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Hamaca 
    
YEAR ENDED DEC. 31, 2005
 
Average sales prices 
Liquids, per barrel $45.24 $48.80 $48.29 $46.97 $50.54 $45.88 $44.40 $48.61 $47.83 $47.56 $45.59 $45.89 
Natural gas, per thousand cubic feet 6.94 8.43 6.90 7.43 0.04 3.59 5.74 3.31 3.48 5.18 0.61 0.26 
Average production costs, per barrel 10.74 8.55 7.57 8.88 4.72 3.38 11.28 4.32 4.93 6.32 2.45 5.53 
    
YEAR ENDED DEC. 31, 2004
  
Average sales prices  
Liquids, per barrel $33.43 $34.69 $34.61 $34.12 $34.85 $31.34 $31.12 $34.58 $33.33 $33.60 $30.23 $23.32  $33.43 $34.69 $34.61 $34.12 $34.85 $31.34 $31.12 $34.58 $33.33 $33.60 $30.23 $23.32 
Natural gas, per thousand cubic feet 5.18 6.08 5.07 5.51 0.04 3.41 3.88 2.68 2.90 4.27 0.65 0.27  5.18 6.08 5.07 5.51 0.04 3.41 3.88 2.68 2.90 4.27 0.65 0.27 
Average production costs, per barrel 8.14 5.26 6.65 6.60 4.89 3.50 9.69 3.47 4.67 5.43 2.31 6.10  8.14 5.26 6.65 6.60 4.89 3.50 9.69 3.47 4.67 5.43 2.31 6.10 
YEAR ENDED DEC. 31, 2003
  
Average sales prices  
Liquids, per barrel $25.77 $27.89 $26.48 $26.66 $28.54 $24.66 $25.10 $27.56 $26.70 $26.69 $22.07 $17.06  $25.77 $27.89 $26.48 $26.66 $28.54 $24.66 $25.10 $27.56 $26.70 $26.69 $22.07 $17.06 
Natural gas, per thousand cubic feet 5.04 5.56 4.51 5.01 0.04 3.64 2.26 2.58 2.87 4.08 0.68 0.33  5.04 5.56 4.51 5.01 0.04 3.64 2.26 2.58 2.87 4.08 0.68 0.33 
Average production costs, per barrel 7.01 4.47 6.40 5.82 4.42 2.49 9.30 3.99 4.41 4.99 2.04 3.24 
YEAR ENDED DEC. 31, 2002
 �� 
Average sales prices 
Liquids, per barrel $20.75 $22.22 $21.13 $21.34 $24.33 $21.52 $22.07 $23.31 $22.92 $22.36 $18.16 $18.91 
Natural gas, per thousand cubic feet 2.98 3.19 2.60 2.89 0.04 3.11 0.84 2.11 2.24 2.62 0.57 – 
Average production costs, per barrel3
 5.91 4.49 6.24 5.48 3.49 2.50 7.94 3.59 4.03 4.63 2.19 1.58  7.01 4.47 6.40 5.82 4.42 2.49 9.30 3.99 4.41 4.99 2.04 3.24 
  
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 20042005 presentation to exclude taxes.

FS-62

TABLE V – RESERVE QUANTITY INFORMATION

Reserves Governance The company has adopted a comprehensive reserves and resource classification system modeled after a system developed and approved by the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. The system classifies recoverable hydrocarbons into six categories based on their status at the time of reporting – three deemed commercial and three noncommercial. Within the commercial classification are proved reserves and two categories of unproved, probable and possible. The noncommercial categories are also referred to as contingent resources. For reserves estimates to be classified as proved, they must meet all SEC standards and demonstrate a high probability of being produced.company standards.
     Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.
     Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.
     Proved reserves do not include additional quantities that may eventually result from extensions of currently proved areas or from applying the secondary or tertiary recovery processes not yet tested and determined to be economic.
     Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change as additional information becomes available.
     Proved reserves are estimated by company asset teams composed of earth scientists and reservoir engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the corporate reserves manager, who is a member of a corporate department that reports directly to the executive vice president responsible for the company’s worldwide exploration and production activities. All of the RAC members are knowledgeable ofin SEC guidelines for proved reserves classification. The RAC coordinates its activities through two operating company-level reserves managers. These two reserves managers are not members of the RAC so as to preserve the corporate-level independence.
     The RAC has the following primary responsibilities: provide independent reviews of the business units’ recommended reserve changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve volumes are calculated using consistent and appropriate standards, procedures and technology; and maintain theCorporate Reserves Manual,, which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.


FS-70

TABLE V — RESERVE QUANTITY INFORMATION — Continued
     During the year, the RAC is represented in meetings with each of the company’s upstream business units to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company’s Strategy and Planning Committee and the Executive Committee, whose members include the Chief Executive Officer and the Chief Financial Officer. The company’s annual reserve activity is also presented to and discussedreviewed with
the Board of Directors. OtherIf major reserves-related issues arechanges to reserves were to occur between the annual reviews, those matters would also be discussed with the Board as necessary throughout the year.Board.
     RAC subteams also conduct in-depth reviews during the year of many of the fields that have the largest proved reserves quantities. These reviews include an examination of the proved reserve records and documentation of their alignment with theCorporate Reserves Manual.
     Reserve Quantities At December 31, 2004, total2005, oil-equivalent reserves for the company’s consolidated operations were 8.2totaled 9.0 billion barrels. (Refer to page E-12E-11 for the definition of oil-equivalent reserves.) Nearly 3022 percent wereof the total was in the United States and about 10 percent in Indonesia.States. Year-end reserves of approximately 1.4 billion barrels were associated with the properties obtained as part of the August 2005 acquisition of Unocal. For the company’s interests in equity affiliates, oil-equivalent reserves were 3.1totaled 2.9 billion barrels, nearly 8584 percent of which werewas associated with the company’s 50 percent ownership in TCO.
     Aside from the TCO operations, no single property accounted for more than 5 percent of the company’s total oil-equivalent proved reserves. Fewer than 20 other individual properties in the company’s portfolio of assets each contained between 1 percent and 45 percent of the company’s oil-equivalent proved reserves, which intotal. In the aggregate, these properties accounted for about 35 percent of the company’s total proved reserves total.oil-equivalent reserves. These other properties were geographically dispersed, located in the United States, South America, Europe, West Africa, the Middle East and the Asia-Pacific region.
     In the United States, total oil-equivalent reserves at year-end 20042005 were 2.42.6 billion barrels. Of this amount, 4539 percent, 2021 percent and 3540 percent were located in California, the Gulf of Mexico and other U.S. areas, respectively.
     In California, liquids reserves represented 95 percent of the total, with most classified as heavy oil. Because of heavy oil’s high viscosity and the need to employ enhanced recovery methods, the producing operations are capital intensive in nature. Most of the company’s heavy-oil fields in California employ a continuous steamflooding process.
     In the Gulf of Mexico region, liquids represented approximately 6063 percent of total oil-equivalent reserves. Production operations are mostly offshore and, as a result, are also capital intensive. Costs include investments in wells, production platforms and other facilities, such as gathering lines and storage facilities.
     In other U.S. areas, the reserves were split about equally between liquids and natural gas. For production of crude oil, some fields utilize enhanced recovery methods, including water-flood and CO2 injection.
     ChevronTexaco operates the Boscan Field in Venezuela under a service agreement, but has not recorded reserve quantities for this operation.
     The pattern of net reserve changes shown in the following tables for the three years ending December 31, 2004,2005, is not necessarily indicative of future trends. TheApart from acquisitions, the company’s ability to add proved reserves is affected by, among other things, matters that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, declines in oil and gas prices, OPEC constraints, geopolitical uncertainties and civil unrest.
     The company’s estimated net proved underground oil and natural gas reserves and changes thereto for the years 2002, 2003, 2004 and 20042005 are shown in the following tables.tables on pages FS-72 and FS-74.


FS-63FS-71

  
Supplemental Information on Oil and Gas Producing Activities –—Continued

TABLE V – RESERVE QUANTITY INFORMATION – Continued

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

                                                
 Consolidated Companies    Consolidated Companies    
 United States International    United States  International    
 Gulf of Total Asia- Total Affiliated Companies  Gulf of Total Asia- Total Affiliated Companies 
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Hamaca 
Millions of barrels Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Hamaca 
         
RESERVES AT JAN. 1, 2002
 1,140 458 703 2,301 1,544 792 1,114 745 4,195 6,496 1,541 487 
Changes attributable to: 
Revisions  (33)  (45)  (38)  (116) 164 41  (155) 17 67  (49) 199 – 
Improved recovery 81 10 8 99 82 – 22 36 140 239 – – 
Extensions and discoveries 3 38 7 48 301 81 4 8 394 442 – – 
Purchases1
 – 2 6 8 – – – – – 8 – – 
Sales2
 – –  (3)  (3) – – – – –  (3) – – 
Production  (89)  (74)  (57)  (220)  (115)  (99)  (96)  (109)  (419)  (639)  (51)  (2)
RESERVES AT DEC. 31, 2002
 1,102 389 626 2,117 1,976 815 889 697 4,377 6,494 1,689 485 
RESERVES AT JAN. 1, 2003
 1,102 389 626 2,117 1,976 815 889 697 4,377 6,494 1,689 485 
Changes attributable to:  
Revisions  (4)  (5) –  (9)  (1) 105  (57) 19 66 57 200 –   (4)  (5) –  (9)  (1) 105  (57) 19 66 57 200 – 
Improved recovery 38 8 7 53 36 – 54 52 142 195 – –  38 8 7 53 36 – 54 52 142 195 – – 
Extensions and discoveries 2 113 9 124 24 15 3 26 68 192 – –  2 113 9 124 24 15 3 26 68 192 – – 
Purchases1
 – 1 – 1 – – – 12 12 13 – –  – 1 – 1 – – – 12 12 13 – – 
Sales2
  (3)  (2)  (18)  (23) –  (42) –  (1)  (43)  (66) – –   (3)  (2)  (18)  (23) –  (42) –  (1)  (43)  (66) – – 
Production  (84)  (69)  (52)  (205)  (112)  (97)  (82)  (109)  (400)  (605)  (49)  (6)  (84)  (69)  (52)  (205)  (112)  (97)  (82)  (109)  (400)  (605)  (49)  (6)
RESERVES AT DEC. 31, 2003
 1,051 435 572 2,058 1,923 796 807 696 4,222 6,280 1,840 479  1,051 435 572 2,058 1,923 796 807 696 4,222 6,280 1,840 479 
Changes attributable to:  
Revisions 13  (68)  (2)  (57)  (70)  (43)  (36)  (12)  (161)  (218) 206  (2) 13  (68)  (2)  (57)  (70)  (43)  (36)  (12)  (161)  (218) 206  (2)
Improved recovery 28 – 6 34 34 – 6 – 40 74 – –  28 – 6 34 34 – 6 – 40 74 – – 
Extensions and discoveries – 8 6 14 77 9 – 17 103 117 – –  – 8 6 14 77 9 – 17 103 117 – – 
Purchases1
 – 2 – 2 – – – – – 2 – –  – 2 – 2 – – – – – 2 – – 
Sales2
 –  (27)  (103)  (130)  (16) – –  (33)  (49)  (179) – –  –  (27)  (103)  (130)  (16) – –  (33)  (49)  (179) – – 
Production  (81)  (56)  (47)  (184)  (115)  (86)  (79)  (101)  (381)  (565)  (52)  (9)  (81)  (56)  (47)  (184)  (115)  (86)  (79)  (101)  (381)  (565)  (52)  (9)
RESERVES AT DEC. 31, 20043
 1,011 294 432 1,737 1,833 676 698 567 3,774 5,511 1,994 468 
RESERVES AT DEC. 31, 2004
 1,011 294 432 1,737 1,833 676 698 567 3,774 5,511 1,994 468 
Changes attributable to: 
Revisions  (23)  (6)  (11)  (40)  (29)  (56)  (108)  (6)  (199)  (239)  (5)  (19)
Improved recovery 57 – 4 61 67 4 42 29 142 203 – – 
Extensions and discoveries – 37 7 44 53 21 1 65 140 184 – – 
Purchases1
 – 49 147 196 4 287 20 65 376 572 – – 
Sales2
  (1) –  (1)  (2) – – –  (58)  (58)  (60) – – 
Production  (79)  (41)  (45)  (165)  (114)  (103)  (74)  (89)  (380)  (545)  (50)  (14)
RESERVES AT DEC. 31, 20053
 965 333 533 1,831 1,814 829 579 573 3,795 5,626 1,939 435 
DEVELOPED RESERVES4
  
At Jan. 1, 2002 885 393 609 1,887 923 648 843 517 2,931 4,818 1,007 38 
At Dec. 31, 2002 867 335 564 1,766 1,042 642 655 529 2,868 4,634 99 63 
At Jan. 1, 2003 867 335 564 1,766 1,042 642 655 529 2,868 4,634 99 63 
At Dec. 31, 2003 832 304 515 1,651 1,059 641 588 522 2,810 4,461 1,304 140  832 304 515 1,651 1,059 641 588 522 2,810 4,461 1,304 140 
At Dec. 31, 2004
 832 192 386 1,410 990 543 490 469 2,492 3,902 1,510 188  832 192 386 1,410 990 543 490 469 2,492 3,902 1,510 188 
At Dec. 31, 2005
 809 177 474 1,460 945 534 439 416 2,334 3,794 1,611 196 
  
1
Includes reserves acquired through property exchanges.
  
2
Includes reserves disposed of through property exchanges.
  
3
Net reserve changes (excluding production) in 20042005 consist of 5490 million barrels of developed reserves and (209)(170) million barrels of undeveloped reserves for consolidated companies and 315(178) million barrels of developed reserves and (111)(154) million barrels of undeveloped reserves for affiliated companies.
  
4
During 2004,2005, the percentages of undeveloped reserves at December 31, 2003,2004, transferred to developed reserves were 1311 percent and 1520 percent for consolidated companies and affiliated companies, respectively.

INFORMATION ON CANADIAN OIL SANDS NET PROVED RESERVES NOT INCLUDED ABOVE:
In addition to conventional liquids and natural gas proved reserves, ChevronTexacoChevron has significant interests in proved oil sands reserves in Canada associated with the Athabasca project. For internal management purposes, ChevronTexacoChevron views these reserves and their development as an integral part of total upstream operations. However, SEC regulations define these reserves as mining-related and not a part of conventional oil and gas reserves. Net proved oil sands reserves were 167146 million barrels as of December 31, 2004. Production began in late 2002.
2005. The oil sands reserves are not considered in the standardized measure of discounted future net cash flows for conventional oil and gas reserves, which is found on page FS-67.FS-76.

     Noteworthy amounts in the categories of proved-reservesproved-reserve changes for 20022003 through 20042005 in the table above table are discussed below:
     Revisions In 2002, net revisions reduced liquids volumes worldwide by 49 million barrels for consolidated companies. International areas accounted for a net increase of 67 million barrels. The largest upward net revision internationally was 161 million barrels for a contract extension in Angola. The largest negative net revision was 155 million barrels in Indonesia, mainly for the effect of higher year-end prices on the calculation of reserves associated with cost-oil recovery under a production-sharing contract. In the United States, the total downward net
revision was 116 million barrels across many fields in each of the geographic sections. The 199-million-barrel increase for the TCO affiliate was associated with the project approval to expand gas processing facilities.
In 2003, net revisions increased reserves by 57 million barrels for consolidated companies. Whereas net U.S. reserve changes were minimal, international volumes increased 66 million barrels. The largest increase was in Kazakhstan in the Asia-Pacific area based on an updated geologic model for one field. The 200-million-barrel increase for TCO was based on an updated model of reservoir and well performance.


FS-64

TABLE V – RESERVE QUANTITY INFORMATION – Continued
     In 2004, net revisions decreased reserves 218 million barrels for consolidated companies and increased reserves
for affiliates by 204 million barrels. For consolidated companies, the decrease was composed of 161 million barrels for international areas and 57 million barrels for the United States. The largest downward revision internationally was 70 million barrels in Africa. One field in Angola accounted for the majority of the net decline as changes were made to oil-in-place estimates based on reservoir performance data. One field in the Asia-Pacific area essentially accounted for the 43-million-barrel downward revision for that region. The revision was associated with reduced well performance. Part of the 36-million-barrel net downward revision for Indonesia was associated with the effect of higher year-end prices on the calculation of reserves for cost-oil recovery under a


FS-72

TABLE V — RESERVE QUANTITY INFORMATION — Continued
production-sharing contract. In the United States, the 68-million-barrel net downward revision in the Gulf of Mexico area was across several fields and based mainly on reservoir analyses and
assessments of well performance. For affiliated companies, the 206-million-barrel increase for TCO was based on an updated assessment of reservoir performance for the Tengiz Field. Partially offsetting this net increase was a downward effect of higher year-end prices on the variable royalty-rate calculation. Downward revisions also occurred in other geographic areas because of the effect of higher year-end prices on various production-sharing terms and variable royalty calculations.
     In 2005, net revisions reduced reserves by 239 million and 24 million barrels for worldwide consolidated companies and equity affiliates, respectively. For consolidated companies, the net decrease was 199 million barrels in the international areas and 40 million barrels in the United States. The largest downward net revisions internationally were 108 million barrels in Indonesia and 53 million barrels in Kazakhstan, due primarily to the effect of higher year-end prices on the calculation of reserves associated with production-sharing and variable-royalty contracts. In the United States, the 40-million-barrel reduction was across many fields in each of the geographic sections. Most of the downward revision for affiliated companies was a 19-million-barrel reduction in Hamaca, attributable to revised government royalty provisions. For TCO, the downward effect of higher year-end prices was partially offset by increased reservoir performance.
Improved Recovery In 2002,2005, improved recovery increased liquids volumes worldwide by 239203 million barrels for consolidated companies. The largestInternational areas accounted for 142 million barrels of the increase. Indonesia added 42 million barrels due to improved performance. Reserve additions of 67 million barrels in Africa occurred primarily in Angola and resulted from infill drilling, wells workovers and secondary recovery from gas injection. Additions of 29 million barrels in the “Other” international area were mainly attributable to improved waterflood performance offshore eastern Canada. An increase of 9961 million barrels occurred in the United States, primarily in the California region due to pattern modifications, injector conversions and infill drillingimproved performance on a large heavy oil field under thermal recovery.
     Extensions and Discoveries In 2002,2005, extensions and discoveries increased liquids volumes worldwide by 442184 million barrels for consolidated companies. The largest increase was 30149 million barrels in Africa, principally 172Nigeria, reflecting new development drilling, including in the Agbami Field, among others. New field developments in Brazil contributed another 41 million barrels reflectingof discoveries. In the project sanctionUnited States, the 44-million-barrel addition was associated mainly with the initial booking of reserves for the Blind Faith Field in the deepwater Gulf of Mexico.
Purchases In 2005, the acquisition of 572 million barrels of liquids related solely to the acquisition of Unocal in August. About three-fourths of the 376 million barrels acquired in the international areas were represented by vol-
umes in Azerbaijan and Thailand. Most volumes acquired in the United States were in Texas and Alaska.
Sales In 2004, sales of liquids volumes reduced reserves of consolidated companies by 179 million barrels. Sales totaled 130 million barrels in the United States and 33 million barrels in the “Other” international region. Sales in the “Other” region of the United States totaled 103 millions barrels, with two fields accounting for approximately one- half of the volume. The 27 million barrels sold in the Gulf of Mexico reflect the sale of a recent discoverynumber of Shelf properties. The “Other” international sales include the disposal of western Canada properties and several fields in Nigeria and 96the United Kingdom. All the sales were associated with the company’s program to dispose of assets deemed nonstrategic to the portfolio of producing properties.
     In 2005, sales of 58 million barrels associated with approvalin the “Other” international area related to the disposition of several development projectsthe former Unocal operations onshore in Angola.Canada.


FS-73

Supplemental Information on Oil and Gas Producing Activities –Continued

TABLE V – RESERVE QUANTITY INFORMATION – Continued

NET PROVED RESERVES OF NATURAL GAS

                                                   
 Consolidated Companies    Consolidated Companies    
 United States International    United States  International    
 Gulf of Total Asia- Total Affiliated Companies  Gulf of Total Asia- Total Affiliated Companies 
Billions of cubic feet Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int'l. Total TCO Hamaca  Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Hamaca 
         
RESERVES AT JAN. 1, 2002
 341 2,361 4,685 7,387 1,872 4,239 520 3,088 9,719 17,106 2,262 42 
Changes attributable to: 
Revisions 16  (200)  (414)  (598) 277 375 15 92 759 161 293 1 
Improved recovery 9 11 1 21 42 – 4 10 56 77 – – 
Extensions and discoveries 5 229 161 395 134 227 33 103 497 892 – – 
Purchases1
 – 65 28 93 – 8 – – 8 101 – – 
Sales2
 – –  (3)  (3) – – – – –  (3) – – 
Production  (46)  (414)  (418)  (878)  (27)  (203)  (54)  (369)  (653)  (1,531)  (66) – 
RESERVES AT DEC. 31, 2002
 325 2,052 4,040 6,417 2,298 4,646 518 2,924 10,386 16,803 2,489 43 
RESERVES AT JAN. 1, 2003
 325 2,052 4,040 6,417 2,298 4,646 518 2,924 10,386 16,803 2,489 43 
Changes attributable to:  
Revisions 25  (106)  (525)  (606) 342 879 36 976 2,233 1,627 109 70  25  (106)  (525)  (606) 342 879 36 976 2,233 1,627 109 70 
Improved recovery 15 7 1 23 17 – 15 35 67 90 – –  15 7 1 23 17 – 15 35 67 90 – – 
Extensions and discoveries – 270 118 388 3 76 12 47 138 526 – –  – 270 118 388 3 76 12 47 138 526 – – 
Purchases1
 – 8 – 8 – 7 – 55 62 70 – –  – 8 – 8 – 7 – 55 62 70 – – 
Sales2
  (1)  (12)  (51)  (64) – – –  (6)  (6)  (70) – –   (1)  (12)  (51)  (64) – – –  (6)  (6)  (70) – – 
Production  (41)  (378)  (394)  (813)  (18)  (235)  (61)  (366)  (680)  (1,493)  (72)  (1)  (41)  (378)  (394)  (813)  (18)  (235)  (61)  (366)  (680)  (1,493)  (72)  (1)
RESERVES AT DEC. 31, 2003
 323 1,841 3,189 5,353 2,642 5,373 520 3,665 12,200 17,553 2,526 112  323 1,841 3,189 5,353 2,642 5,373 520 3,665 12,200 17,553 2,526 112 
Changes attributable to:  
Revisions 27  (391)  (316)  (680) 346 236 21 325 928 248 963 23  27  (391)  (316)  (680) 346 236 21 325 928 248 963 23 
Improved recovery 2 – 1 3 7 – 13 – 20 23 – –  2 – 1 3 7 – 13 – 20 23 – – 
Extensions and discoveries 1 54 89 144 16 39 2 13 70 214 – –  1 54 89 144 16 39 2 13 70 214 – – 
Purchases1
 – 5 – 5 – 4 – – 4 9 – –  – 5 – 5 – 4 – – 4 9 – – 
Sales2
 –  (147)  (289)  (436) – – –  (111)  (111)  (547) – –  –  (147)  (289)  (436) – – –  (111)  (111)  (547) – – 
Production  (39)  (298)  (348)  (685)  (32)  (247)  (54)  (354)  (687)  (1,372)  (76)  (1)  (39)  (298)  (348)  (685)  (32)  (247)  (54)  (354)  (687)  (1,372)  (76)  (1)
RESERVES AT DEC. 31, 20043
 314 1,064 2,326 3,704 2,979 5,405 502 3,538 12,424 16,128 3,413 134 
RESERVES AT DEC. 31, 2004
 314 1,064 2,326 3,704 2,979 5,405 502 3,538 12,424 16,128 3,413 134 
Changes attributable to: 
Revisions 21  (15)  (15)  (9) 211  (428)  (31) 243  (5)  (14)  (547) 49 
Improved recovery 8 – – 8 13 – – 31 44 52 – – 
Extensions and discoveries – 68 99 167 25 118 5 55 203 370 – – 
Purchases1
 – 269 899 1,168 5 3,962 247 274 4,488 5,656 – – 
Sales2
 – –  (6)  (6) – – –  (248)  (248)  (254) – – 
Production  (39)  (215)  (350)  (604)  (42)  (434)  (77)  (315)  (868)  (1,472)  (79)  (2)
RESERVES AT DEC. 31, 20053
 304 1,171 2,953 4,428 3,191 8,623 646 3,578 16,038 20,466 2,787 181 
DEVELOPED RESERVES4
  
At Jan. 1, 2002 284 1,976 3,986 6,246 444 2,920 250 2,231 5,845 12,091 1,477 6 
At Dec. 31, 2002 266 1,770 3,600 5,636 582 2,934 262 2,157 5,935 11,571 1,474 6 
At Jan. 1, 2003 266 1,770 3,600 5,636 582 2,934 262 2,157 5,935 11,571 1,474 6 
At Dec. 31, 2003 265 1,572 2,964 4,801 954 3,627 223 3,043 7,847 12,648 1,789 52  265 1,572 2,964 4,801 954 3,627 223 3,043 7,847 12,648 1,789 52 
At Dec. 31, 2004
 252 937 2,191 3,380 1,108 3,701 271 2,273 7,353 10,733 2,584 63  252 937 2,191 3,380 1,108 3,701 271 2,273 7,353 10,733 2,584 63 
At Dec. 31, 2005
 251 977 2,794 4,022 1,346 4,819 449 2,453 9,067 13,089 2,314 85 
  
1
Includes reserves acquired through property exchanges.
  
2
Includes reserves disposed of through property exchanges.
  
3
Net reserve changes (excluding production) in 20042005 consist of (543)5,141 billion cubic feet of developed reserves and 490669 billion cubic feet of undeveloped reserves for consolidated companies and 883(672) billion cubic feet of developed reserves and 103174 billion cubic feet of undeveloped reserves for affiliated companies.
  
4
During 2004,2005, the percentages of undeveloped reserves at December 31, 2003,2004, transferred to developed reserves were 412 percent and 619 percent for consolidated companies and affiliated companies, respectively.

FS-65

Supplemental Information on Oil and Gas Producing Activities –Continued

TABLE V – RESERVE QUANTITY INFORMATION – Continued

Sales In 2004, sales of liquids volumes reduced reserves of consolidated companies by 179 million barrels. Sales totaled 130 million barrels in the United States and 33 million barrels in the “other” international region. Sales in the “other” region of the United States totaled 103 millions barrels, with two fields accounting for approximately one-half of the volume. The 27 million barrels sold in the Gulf of Mexico reflect the sale of a number of Shelf properties. The “other” international sales include the disposal of western Canada properties and several fields in the United Kingdom. All the sales were associated with the company’s program to dispose of assets deemed nonstrategic to the portfolio of producing properties.
     Noteworthy amounts in the categories of proved-reservesproved-reserve changes for 20022003 through 20042005 in the table on page FS-65above are discussed below:
     Revisions In 2002, reserves were revised upward by a net 161 billion cubic feet (BCF) for consolidated companies, as increases of 759 BCF internationally were partially offset by net downward revisions of 598 BCF in the United States. Internationally, the majority of the 277 BCF net upward revision in Africa was associated primarily with a performance assessment of several fields and a multifield gas development project. An increase of 375 BCF in the Asia-Pacific region included the effect of securing a contract to supply LNG to China markets from company producing operations in Australia. In the United States, about one-fourth of the 598 BCF net downward revision was associated with two fields in the midcontinent region based on an updated assessment of production performance and changes to operating conditions of the wells. Most of the remaining negative revision was associated with reviews of performance in many fields. For the TCO affiliate in Kazakhstan, the 293 BCF increase related mainly to project approval to expand gas processing facilities.
In 2003, revisions accounted for a net increase of 1,627 BCF for consolidated companies, as net increases of 2,233 BCF internationally were partially offset by net downward revisions of 606 BCF in the United States. Internationally, the net 879 BCF increase in the Asia-Pacific region related primarily to Australia and Kazakhstan. In Australia, the increase was associated mainly with a change to the probabilistic method of aggregating the reserves for multiple fields produced through common offshore infrastructure into a single LNG plant. The increase in Kazakhstan related to an updated geologic model for one
field and higher gas sales to a third-party processing plant. The net 976 BCF increase in the “Other” international area was mainly the result of operating contract extensions for two fields in South America. In the United States, about one-third of the net 606 BCF negative revision related to two coal bed methane fields in the midcontinentMid-Continent region, based on performance data for producing wells. Downward revisions for the balance of the write-down were associated with several fields, based on assessments of well performance and other data.
     In 2004, revisions increased reserves for consolidated companies by a net 248 BCF, composed of increases of 928 BCF internationally and decreases of 680 BCF in the United States. Internationally, about half of the 346 BCF


FS-74

TABLE V — RESERVE QUANTITY INFORMATION – Continued
increase in Africa related to properties in Nigeria, for which changes were associated with well performance reviews, development drilling and lease fuel calculations. The 236 BCF addition in the Asia-Pacific
region was related primarily to reservoir analysis for a single field. Most of the 325 BCF in the “Other” international area is related to a new gas sales contract in Trinidad and Tobago. In the United States, the net 391 BCF downward revision in the Gulf of Mexico was related to well-performance reviews and technical analyses in several fields. Most of the net 316 BCF negative revision in the “Other” U.S. area related to two coal bed methane fields in the midcontinentMid-Continent region and their associated wells’ performance. The 963 BCF increase for TCO was connected with updated analyses of reservoir performance and processing plant yields.
     Extensions and DiscoveriesIn 2002,2005, reserves were revised downward by 14 BCF for consolidated companies increased reserves by 892and 498 BCF including 395 BCF in the United States and 227for equity affiliates. For consolidated companies, negative revisions were 428 BCF in the Asia-Pacific region. InMost of the decrease was attributable to one field in Kazakhstan, due mainly to the effects of higher year-end prices on variable-royalty provisions of the production-sharing contract. Reserves additions for consolidated companies totaled 211 BCF and 243 BCF in Africa and “Other,” respectively. The majority of the African region changes were in Angola, due to a revised forecast of fuel gas usage, and in Nigeria from improved reservoir performance. The availability of third-party compression in Colombia accounted for most of the increase in the “Other” region. Revisions in the United States 229decreased reserves by 9 BCF, was addedas nominal increases in the San Joaquin Valley were more than offset by decreases in the Gulf of Mexico and 161“Other” region. For the TCO affiliate in Kazakhstan, a reduction of 547 BCF inreflects the “other” region, primarily due to drilling activities. The addition in Asia-Pacific resulted fromupdated forecast of future royalties payable and year-end price effects, partially offset by volumes added as a gas supply contract in Australia that enabled bookingresult of a previous discovery.an updated assessment of reservoir performance.
Extensions and Discoveries In 2003, extensions and discoveries accounted for an increase of 526 BCF for consolidated companies, reflecting a 388 BCF increase in the United States, with 270 BCF added in the Gulf of Mexico and 118 BCF in the “other”“Other” region. The Gulf of Mexico increase includes discoveries in several offshore Louisiana fields, with a large number of fields in Texas, Louisiana and other states accounting for the increase in “other.“Other.”
     In 2004, extensions and discoveries accounted for an increase of 214 BCF, reflecting an increase in the United States of 144 BCF, with 89 BCF added in the “other”“Other” region and 54 BCF added in the Gulf of Mexico through drilling activities in a large number of fields.
     In 2005, consolidated companies increased reserves by 370 BCF, including 167 BCF in the United States and 118 BCF in the Asia-Pacific region. In the United States, 99 BCF was added in the “Other” region and 68 BCF in the Gulf of Mexico, primarily due to drilling activities. The addition in Asia-Pacific resulted primarily from increased drilling in Kazakhstan.
Purchases In 2005, all except 7 BCF of the 5,656 BCF total purchases were associated with the Unocal acquisition. International reserve acquisitions were 4,488 BCF, with Thailand accounting for about half the volumes. Other significant volumes were added in Bangladesh and Myanmar.
     Sales In 2004, sales for consolidated companies totaled 547 BCF. Of this total, 436 BCF was in the United States and 111 BCF in the “other”“Other” international region. In the United States, “other”“Other” region sales accounted for 289 BCF, reflecting the disposal of a large number of smaller properties, including a coal bed methane field. Gulf of Mexico sales of 147 BCF reflected the sale of Shelf properties, with four fields accounting for more than one-third of the total sales. Sales in the “other”“Other” international region reflected the disposition of the properties in Westernwestern Canada and the United Kingdom.
     In 2005, sales of 248 BCF in the “Other” international region related to the disposition of former-Unocal’s onshore properties in Canada.


FS-66FS-75

Supplemental Information on Oil and Gas Producing Activities –Continued

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

The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FAS 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions, and include estimated costs for asset retirement obligations. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated
using 10 percent
midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced.
     The information provided does not represent management’s estimate of the company’s expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under FAS 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the company’s future cash flows or value of its oil and gas reserves. In the following table, “Standardized Measure Net Cash Flows” refers to the standardized measure of discounted future net cash flows.


                                                 
  Consolidated Companies    
  United States  International        
      Gulf of      Total      Asia-          Total      Affiliated Companies 
Millions of dollars Calif.  Mexico  Other  U.S.  Africa  Pacific  Indonesia  Other  Int’l.  Total  TCO  Hamaca 
       
AT DECEMBER 31, 2004
                                                
Future cash inflows from production $32,793  $19,043  $28,676  $80,512  $64,628  $35,960  $25,313  $30,061  $155,962  $236,474  $61,875  $12,769 
Future production costs  (11,245)  (3,840)  (7,343)  (22,428)  (10,662)  (8,604)  (12,830)  (7,884)  (39,980)  (62,408)  (7,322)  (3,734)
Future devel. costs  (1,731)  (2,389)  (667)  (4,787)  (6,355)  (2,531)  (717)  (1,593)  (11,196)  (15,983)  (5,366)  (407)
Future income taxes  (6,706)  (4,336)  (6,991)  (18,033)  (29,519)  (9,731)  (5,354)  (9,914)  (54,518)  (72,551)  (13,895)  (2,934)
 
Undiscounted future net cash flows  13,111   8,478   13,675   35,264   18,092   15,094   6,412   10,670   50,268   85,532   35,292   5,694 
10 percent midyear annual discount for timing of estimated cash flows  (6,656)  (2,715)  (6,110)  (15,481)  (9,035)  (6,966)  (2,465)  (3,451)  (21,917)  (37,398)  (22,249)  (3,817)
 
STANDARDIZED MEASURE NET CASH FLOWS
 $6,455  $5,763  $7,565  $19,783  $9,057  $8,128  $3,947  $7,219  $28,351  $48,134  $13,043  $1,877 
 
AT DECEMBER 31, 2003
                                                
Future cash inflows from production $30,307  $23,521  $33,251  $87,079  $55,532  $33,031  $26,288  $29,987  $144,838  $231,917  $56,485  $9,018 
Future production costs  (10,692)  (5,003)  (9,354)  (25,049)  (8,237)  (6,389)  (11,387)  (6,334)  (32,347)  (57,396)  (6,099)  (1,878)
Future devel. costs  (1,668)  (1,550)  (990)  (4,208)  (4,524)  (2,432)  (1,729)  (1,971)  (10,656)  (14,864)  (6,066)  (463)
Future income taxes  (6,073)  (5,742)  (7,752)  (19,567)  (25,369)  (9,932)  (5,993)  (7,888)  (49,182)  (68,749)  (12,520)  (2,270)
 
Undiscounted future net cash flows  11,874   11,226   15,155   38,255   17,402   14,278   7,179   13,794   52,653   90,908   31,800   4,407 
10 percent midyear annual discount for timing of estimated cash flows  (6,050)  (3,666)  (7,461)  (17,177)  (8,482)  (6,392)  (3,013)  (5,039)  (22,926)  (40,103)  (20,140)  (2,949)
 
STANDARDIZED MEASURE NET CASH FLOWS
 $5,824  $7,560  $7,694  $21,078  $8,920  $7,886  $4,166  $8,755  $29,727  $50,805  $11,660  $1,458 
 
AT DECEMBER 31, 2002*
                                                
Future cash inflows from production $27,111  $19,671  $31,130  $77,912  $52,513  $31,099  $28,451  $26,531  $138,594  $216,506  $52,457  $9,777 
Future production costs  (11,071)  (5,167)  (10,077)  (26,315)  (6,435)  (4,534)  (9,552)  (5,970)  (26,491)  (52,806)  (4,959)  (1,730)
Future devel. costs  (1,769)  (748)  (1,116)  (3,633)  (3,454)  (2,516)  (1,989)  (1,868)  (9,827)  (13,460)  (5,377)  (578)
Future income taxes  (4,829)  (4,655)  (6,747)  (16,231)  (25,060)  (10,087)  (7,694)  (6,797)  (49,638)  (65,869)  (11,899)  (2,540)
 
Undiscounted future net cash flows  9,442   9,101   13,190   31,733   17,564   13,962   9,216   11,896   52,638   84,371   30,222   4,929 
10 percent midyear annual discount for timing of estimated cash flows  (4,713)  (2,493)  (6,666)  (13,872)  (8,252)  (6,297)  (3,674)  (3,691)  (21,914)  (35,786)  (18,964)  (3,581)
 
STANDARDIZED MEASURE NET CASH FLOWS
 $4,729  $6,608  $6,524  $17,861  $9,312  $7,665  $5,542  $8,205  $30,724  $48,585  $11,258  $1,348 
 
* 2002 includes certain reclassifications to conform to 2004 presentation.

FS-67FS-76

  
TABLE VI – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES – Continued
                                                 
  Consolidated Companies    
  United States  International        
      Gulf of      Total      Asia-          Total      Affiliated Companies 
Millions of dollars Calif.  Mexico  Other  U.S.  Africa  Pacific Indonesia  Other  Int’l.  Total  TCO  Hamaca 
     
AT DECEMBER 31, 2005
                                                
Future cash inflows from production $50,771  $29,422  $50,039  $130,232  $101,912  $73,612  $32,538  $44,680  $252,742  $382,974  $97,707  $20,616 
Future production costs  (15,719)  (5,758)  (12,767)  (34,244)  (11,366)  (12,459)  (18,260)  (11,908)  (53,993)  (88,237)  (7,399)  (2,101)
Future devel. costs  (2,274)  (2,467)  (873)  (5,614)  (8,197)  (5,840)  (1,730)  (2,439)  (18,206)  (23,820)  (5,996)  (762)
Future income taxes  (11,092)  (7,173)  (12,317)  (30,582)  (50,894)  (21,509)  (5,709)  (13,917)  (92,029)  (122,611)  (23,818)  (6,036)
 
Undiscounted future net cash flows  21,686   14,024   24,082   59,792   31,455   33,804   6,839   16,416   88,514   148,306   60,494   11,717 
10 percent midyear annual discount for timing of estimated cash flows  (10,947)  (4,520)  (10,838)  (26,305)  (14,881)  (14,929)  (2,269)  (5,635)  (37,714)  (64,019)  (37,674)  (7,768)
 
STANDARDIZED MEASURE NET CASH FLOWS
 $10,739  $9,504  $13,244  $33,487  $16,574  $18,875  $4,570  $10,781  $50,800  $84,287  $22,820  $3,949 
 
AT DECEMBER 31, 2004
                                                
Future cash inflows from production $32,793  $19,043  $28,676  $80,512  $64,628  $35,960  $25,313  $30,061  $155,962  $236,474  $61,875  $12,769 
Future production costs  (11,245)  (3,840)  (7,343)  (22,428)  (10,662)  (8,604)  (12,830)  (7,884)  (39,980)  (62,408)  (7,322)  (3,734)
Future devel. costs  (1,731)  (2,389)  (667)  (4,787)  (6,355)  (2,531)  (717)  (1,593)  (11,196)  (15,983)  (5,366)  (407)
Future income taxes  (6,706)  (4,336)  (6,991)  (18,033)  (29,519)  (9,731)  (5,354)  (9,914)  (54,518)  (72,551)  (13,895)  (2,934)
 
Undiscounted future net cash flows  13,111   8,478   13,675   35,264   18,092   15,094   6,412   10,670   50,268   85,532   35,292   5,694 
10 percent midyear annual discount for timing of estimated cash flows  (6,656)  (2,715)  (6,110)  (15,481)  (9,035)  (6,966)  (2,465)  (3,451)  (21,917)  (37,398)  (22,249)  (3,817)
 
STANDARDIZED MEASURE NET CASH FLOWS
 $6,455  $5,763  $7,565  $19,783  $9,057  $8,128  $3,947  $7,219  $28,351  $48,134  $13,043  $1,877 
 
AT DECEMBER 31, 2003
                                                
Future cash inflows from production $30,307  $23,521  $33,251  $87,079  $55,532  $33,031  $26,288  $29,987  $144,838  $231,917  $56,485  $9,018 
Future production costs  (10,692)  (5,003)  (9,354)  (25,049)  (8,237)  (6,389)  (11,387)  (6,334)  (32,347)  (57,396)  (6,099)  (1,878)
Future devel. costs  (1,668)  (1,550)  (990)  (4,208)  (4,524)  (2,432)  (1,729)  (1,971)  (10,656)  (14,864)  (6,066)  (463)
Future income taxes  (6,073)  (5,742)  (7,752)  (19,567)  (25,369)  (9,932)  (5,993)  (7,888)  (49,182)  (68,749)  (12,520)  (2,270)
 
Undiscounted future net cash flows  11,874   11,226   15,155   38,255   17,402   14,278   7,179   13,794   52,653   90,908   31,800   4,407 
10 percent midyear annual discount for timing of estimated cash flows  (6,050)  (3,666)  (7,461)  (17,177)  (8,482)  (6,392)  (3,013)  (5,039)  (22,926)  (40,103)  (20,140)  (2,949)
 
STANDARDIZED MEASURE NET CASH FLOWS
 $5,824  $7,560  $7,694  $21,078  $8,920  $7,886  $4,166  $8,755  $29,727  $50,805  $11,660  $1,458 
 

FS-77

Supplemental Information on Oil and Gas Producing Activities –Continued

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

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


                                  
 Consolidated Companies* Affiliated Companies  Consolidated Companies*  Affiliated Companies
Millions of dollars 2004 2003 2002 2004 2003 2002  2005   2004 2003 2005   2004 2003 
         
PRESENT VALUE AT JANUARY 1
 $50,805   $48,585 $23,748 $13,118   $12,606 $6,396  $ 48,134   $ 50,805 $ 48,585 $ 14,920   $ 13,118 $ 12,606 
         
Sales and transfers of oil and gas produced net of production costs  (18,843)   (16,630)  (13,161)  (1,602)   (1,054)  (829)  (26,145)   (18,843)  (16,630)  (2,712)   (1,602)  (1,054)
Development costs incurred 3,579   3,451 3,695 1,104   750 800  5,504   3,579 3,451 810   1,104 750 
Purchases of reserves 58   97 181 –   – –  25,307   58 97 –   – – 
Sales of reserves  (3,734)   (839)  (42) –   – –   (2,006)   (3,734)  (839) –   – – 
Extensions, discoveries and improved recovery less related costs 2,678   5,445 7,472 –   – –  7,446   2,678 5,445 –   – – 
Revisions of previous quantity estimates 1,611   1,200 180 970   653 917   (13,564)  1,611 1,200  (2,598)  970 653 
Net changes in prices, development and production costs 6,173   1,857 40,802 266    (1,187) 6,722  61,370   6,173 1,857 19,205   266  (1,187)
Accretion of discount 8,139   7,903 3,987 1,818   1,709 895  8,160   8,139 7,903 2,055   1,818 1,709 
Net change in income tax  (2,332)   (264)  (18,277)  (754)   (359)  (2,295)  (29,919)   (2,332)  (264)  (4,911)   (754)  (359)
         
Net change for the year  (2,671)  2,220 24,837 1,802   512 6,210  36,153    (2,671) 2,220 11,849   1,802 512 
         
PRESENT VALUE AT DECEMBER 31
 $48,134   $50,805 $48,585 $14,920   $13,118 $12,606  $ 84,287   $ 48,134 $ 50,805 $ 26,769   $ 14,920 $ 13,118 
       
*2003 and 2002 conformed to 2004 and 2005 presentation.

FS-68FS-78

EXHIBIT INDEX
     
Exhibit No.  Description
   
 3.1 Restated Certificate of Incorporation of ChevronTexaco Corporation, dated October 9, 2001, filed as Exhibit 3.1 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
 
 3.2 By-Laws of ChevronTexaco Corporation, as amended September 26, 2001, filed as Exhibit 3.2 for ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.
    Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the corporation and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Commission upon request.
 
 10.1 ChevronTexaco Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, approved by the company’s stockholders on May 22, 2003, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated March 24, 2003, and incorporated herein by reference.
 
 10.2 Management Incentive Plan of ChevronTexaco Corporation, as amended effective October 9, 2001, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated April 15, 2002, and incorporated herein by reference.
 
 10.3 ChevronTexaco Corporation Excess Benefit Plan, amended and restated as of April 1, 2002, filed as Exhibit 10.3 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated herein by reference.
 
 10.4 ChevronTexaco Corporation Long-Term Incentive Plan, including January 28, 2004 amendments, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated March 26, 2004 and incorporated herein by reference.
 
 10.6 ChevronTexaco Corporation Deferred Compensation Plan for Management Employees, as amended and restated effective April 1, 2002, filed as Exhibit 10.1 to ChevronTexaco Corporation’s Report on Form 10-Q for the quarterly period ended March 31, 2002, and incorporated herein by reference.
 
 10.8 Texaco Inc. Stock Incentive Plan, adopted May 9, 1989, as amended May 13, 1993, and May 13, 1997, filed as Exhibit 10.13 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
 
 10.9 Supplemental Pension Plan of Texaco Inc., dated June 26, 1975, filed as Exhibit 10.14 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
 
 10.10 Supplemental Bonus Retirement Plan of Texaco Inc., dated May 1, 1981, filed as Exhibit 10.15 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
 
 10.11 Texaco Inc. Director and Employee Deferral Plan approved March 28, 1997, filed as Exhibit 10.16 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
 
 10.12 ChevronTexaco Corporation 1998 Stock Option Program for U.S. Dollar Payroll Employees, filed as Exhibit 10.12 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.
 
 12.1* Computation of Ratio of Earnings to Fixed Charges (page E-3).
     
Exhibit No. Description
   
 2.1 Amendment No. 1 to Agreement and Plan of Merger dated as of July 19, 2005, by and among Unocal Corporation, Chevron Corporation and Blue Merger Sub Inc., filed as Annex A to Exhibit 20.1 to Chevron’s Current Report on Form 8-K dated July 25, 2005, and incorporated herein by reference.
 
 3.1 Restated Certificate of Incorporation of Chevron Corporation, dated May 9, 2005, filed as Exhibit 99.1 to Chevron’s Current Report on Form 8-K dated July 25, 2005, and incorporated herein by reference.
 
 3.2 By-Laws of Chevron Corporation, as amended June 29, 2005, filed as Exhibit 3.2 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2005, and incorporated herein by reference.
 
 4  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 Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, approved by the company’s stockholders on May 22, 2003, filed as Appendix A to Chevron Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated March 24, 2003, and incorporated herein by reference.
 
 10.2 Management Incentive Plan of Chevron Corporation, as amended and restated on December 7, 2005, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K dated December 7, 2005, and incorporated herein by reference.
 
 10.3 Chevron Corporation Excess Benefit Plan, amended and restated as of April 1, 2002, filed as Exhibit 10.3 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, and incorporated herein by reference.
 
 10.4 Chevron Corporation Long-Term Incentive Plan, as amended and restated on December 7, 2005, filed as Exhibit 10.4 to Chevron Corporation’s Current Report on Form 8-K dated December 7, 2005, and incorporated herein by reference.
 
 10.6 Chevron Corporation Deferred Compensation Plan for Management Employees, as amended and restated on December 7, 2005, filed as Exhibit 10.5 to Chevron Corporation’s Current Report on Form 8-K dated December 7, 2005, 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 Chevron 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 Chevron 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 Chevron 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 Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.

E-1

     
Exhibit No.  Description
   
 
 21.1* Subsidiaries of ChevronTexaco Corporation (page E-4 to E-5).
 
 23.1* Consent of PricewaterhouseCoopers LLP (page E-6).
 
 24.1 Powers of Attorney for directors of ChevronTexaco Corporation, authorizing the
 to 24.10* signing of the Annual Report on Form 10-K on their behalf.
 
 31.1* Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Executive Officer (page E-7).
 
 31.2* Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Financial Officer (page E-8).
 
 32.1* Section 1350 Certification of the company’s Chief Executive Officer (page E-9).
 
 32.2* Section 1350 Certification of the company’s Chief Financial Officer (page E-10).
 
 99.1* Submission of Matters to a Vote of Security Holders (page E-11).
 
 99.2* Definitions of Selected Energy and Financial Terms (page E-12).
     
Exhibit No. Description
   
 10.12 Chevron Corporation 1998 Stock Option Program for U.S. Dollar Payroll Employees, filed as Exhibit 10.12 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.
 
 10.13 Summary of Chevron’s Management and Incentive Plan Awards and Criteria, filed as Exhibit 10.13 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005, and incorporated herein by reference.
 
 10.14 Chevron Corporation Change in Control Surplus Employee Severance Program For Salary Grades 41 and Above, as amended on December 7, 2005, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K dated December 7, 2005, and incorporated herein by reference.
 
 10.15 Chevron Corporation Benefit Protection Program, as amended and restated on December 7, 2005, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K dated December 7, 2005, and incorporated herein by reference.
 
 10.16 Form of Notice of Grant under the Chevron Corporation Long-Term Incentive Plan, filed as Exhibit 10.1 to Chevron’s Current Report on Form 8-K dated June 29, 2005, and incorporated herein by reference.
 
 10.17 Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.2 to Chevron’s Current Report on Form 8-K dated June 29, 2005, and incorporated herein by reference.
 
 12.1* Computation of Ratio of Earnings to Fixed Charges (page E-3).
 
 21.1* Subsidiaries of Chevron Corporation (page E-4 to E-5).
 
 23.1* Consent of PricewaterhouseCoopers LLP (page E-6).
 
 24.1 Powers of Attorney for directors and certain officers of Chevron Corporation, authorizing the signing of
 to 24.12 the Annual Report on Form 10-K on their behalf.
 
 31.1* Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Executive Officer (page E-7).
 
 31.2* Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Financial Officer (page E-8).
 
 32.1* Section 1350 Certification of the company’s Chief Executive Officer (page E-9).
 
 32.2* Section 1350 Certification of the company’s Chief Financial Officer (page E-10).
 
 99.1* Definitions of Selected Energy and Financial Terms (page E-11).
* Filed herewith.
Copies of above exhibits not contained herein are available, to any security holder upon written request to the Corporate Governance Department, ChevronTexacoChevron Corporation, 6001 Bollinger Canyon Road, San Ramon, California 94583.94583-2324.

E-2