CHEVRONTEXACO CORP - 10-Q Quarterly Report

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o

Indicate the number of shares of each of the issuer’s classes of common stock, as of the latest practicable date:

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

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

The accompanying consolidated financial statements of ChevronTexaco Corporation and its subsidiaries (the company) have not been audited by independent accountants, except for the Consolidated Balance Sheet at December 31, 2002. In the opinion of the company’s management, the interim data include all adjustments necessary for a fair statement of the results for the interim periods. These adjustments were of a normal recurring nature, except for the cumulative effect of changes in accounting principles, special items and merger-related expenses described in Notes 2 and 3, including items relating to the company’s investment in Dynegy Inc. (Dynegy) discussed in detail in Notes 2 and 4.

Certain notes and other information have been condensed or omitted from the interim financial statements presented in this Quarterly Report on Form 10-Q. Therefore, these financial statements should be read in conjunction with the company’s 2002 Annual Report on Form 10-K.

The results for the three- and nine-month periods ended September 30, 2003, are not necessarily indicative of future financial results.

Net income for the third quarter 2003 was $1.975 billion. Included in this amount was a net benefit of $14 million from special items, composed of net gains totaling $447 million that were substantially offset by net charges of $433 million. The gain amount included $365 million related to the exchange of the company’s $1.5 billion investment in Dynegy convertible preferred stock for cash and other Dynegy securities, and $82 million for the net effect of asset dispositions. The special charges were for asset impairments — $215 million, environmental remediation accruals — $132 million, and employee termination benefits related to restructurings and reorganizations — $86 million.

A net loss of $904 million was recorded in the third quarter of 2002. Included in this amount were net special charges of $2.141 billion. Largest among these net charges were $1.549 billion related to the company’s investment in Dynegy and $485 million for asset impairments.

Net income for the first nine months of 2003 was $5.495 billion, compared with $228 million in the year-ago period. In addition to the third quarter 2003 net gain from special items, net income for the nine months 2003 included charges of $196 million for the cumulative effect of changes in accounting principles, mainly relating to a new accounting standard for asset retirement obligations, net charges of $117 million primarily for the write-down of assets in anticipation of their sale, and $39 million for the company’s share of losses from asset sales and impairments by an international equity affiliate.

Net income for the first nine months of 2002 was $228 million, including net special charges of $3.173 billion. The net special charges included $2.254 billion related to Dynegy, $485 million for asset impairments and other asset revaluations, $278 million for merger-related expenses, $113 million for environmental remediation reserves and $43 million for other items.

Foreign currency losses of $31 million were included in net income for the third quarter of 2003, compared with gains of $65 million in the year-ago period. This adverse change was the result of the weakening of the U.S. dollar against the currencies of several countries, including those of Australia, the United Kingdom and Argentina. For the first nine months of 2003, foreign currency losses were $233 million, compared with gains of $36 million in the corresponding 2002 period. The nine-month change primarily reflected significant gains that were recorded in the first half of 2002 attributable to the devaluation of the Argentine peso.

The company adopted Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143), effective January 1, 2003. This new accounting standard applies to legal obligations associated with the retirement of tangible long-lived assets. FAS 143 primarily affects the company’s accounting for oil and gas producing assets and differs in several respects from previous accounting under FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.”

In the first quarter 2003, the company recorded a net after-tax charge of $200 million 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 billion; “Accrued liabilities,” $115 million; and, “Deferred credits and other noncurrent obligations,” $2.674 billion. “Noncurrent deferred income taxes” decreased by $21 million.

Upon adoption, legal obligations, if any, to retire refining, marketing and transportation (downstream) and chemical long-lived assets generally were not recognized, as indeterminate settlement dates for the asset retirements prevented estimation of the fair value of the associated retirement obligation (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 the third quarter and nine months 2003 was not materially different from what the result would have been under FAS 19 accounting. Included in “Depreciation, depletion and amortization” of $1.409 billion and $4.062 billion in the third quarter and nine months 2003, respectively, was $42 million and $128 million, respectively, of expenses related to asset retirement obligations.

The following table illustrates what the company’s net income and net income per share would have been in the third quarter and nine months 2002 if the provisions of FAS 143 had been applied in that period, compared with net income and net income per share recorded in the corresponding 2003 periods.


(1)	The amounts in 2003 include a benefit of $0.16 for the company’s share of a capital stock transaction of its Dynegy 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.

ChevronTexaco owns an approximate 26 percent equity interest in the common stock of Dynegy — an energy merchant engaged in power generation, natural gas liquids processing and marketing and regulated energy delivery. At the beginning of the 2003 third quarter, the company also held $1.5 billion aggregate principal amount of Dynegy Series B Preferred Stock, which was due for redemption at par value in November 2003.

Exchange of Series B Preferred Stock for Cash and New Dynegy Securities. On August 11, 2003, the company exchanged the Dynegy Series B Preferred Stock for $225 million in cash, $225 million face value of Dynegy Junior Unsecured Subordinated Notes due 2016 and $400 million face value of Dynegy Series C Convertible Preferred Stock with a stated maturity of 2033.

$225 million cash, the total amount recorded on the date of exchange was $665 million. A gain of $365 million was recorded in the statement of income at that date for the difference between the $665 million fair value received and the net balance sheet amount of $300 million associated with the Series B shares.

At September 30, 2003, the estimated fair values of the Junior Notes and Series C shares totaled $475 million. The $35 million increase from the $440 million recorded at August 11, 2003, was recorded to “Investments and Advances,” with an offsetting amount in “Other Comprehensive Income.” Future temporary changes in the estimated fair values of the new securities likewise will be reported in “Other Comprehensive Income.” However, if any future declines in fair value are deemed to be other than temporary, such declines would be recorded against income in the period. Interest that accrues on the notes and dividends payable on the preferred stock will be recognized in income each period.

In addition to the $365 million gain recorded in income in the third quarter 2003, the company also recorded $170 million directly to “Retained Earnings”, which represented the company’s approximate 26 percent equity share of a gain recorded by Dynegy in connection with the Series B exchange transaction. Under the accounting rules applicable to preferred stock redemptions, the company increased its earnings per share in the third quarter 2003 by $0.16 for the effect of the $170 million recorded directly to “Retained Earnings.”

Investment in Dynegy Common Stock. At September 30, 2003, the carrying value of the company’s investment in Dynegy common stock was $217 million. This amount was about $450 million below the company’s proportionate interest in Dynegy’s underlying net assets. This difference resulted from write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value of the investment at the time that were deemed to be other than temporary. The $450 million difference has been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors giving rise to the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and Dynegy’s historical book values.

On November 3, 2003, Dynegy announced an agreement to sell substantially all of the assets and liabilities of its Illinois Power subsidiary to Exelon Corporation. Dynegy has stated that it expects to record a charge against earnings in the fourth quarter 2003 for a write-down of the carrying value of the related assets. ChevronTexaco plans to include its approximate 26 percent share of that loss in the same period as Dynegy.

The “Net decrease in operating working capital” was composed of operating changes of the following:

“Net Cash Provided by Operating Activities” included the following cash payments for interest on debt and for income taxes:

The “Net sales (purchases) of marketable securities” consisted of the following gross amounts:

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


(1)	2003 includes $210 million deferred payment related to the 1993 acquisition of the company’s interest in the Tengizchevroil joint venture.

The Consolidated Statement of Cash Flows excludes the following non-cash transactions:

The company’s Employee Stock Ownership Plan (ESOP) repaid $50 million and $100 million of matured debt guaranteed by ChevronTexaco Corporation in January 2003 and 2002, respectively. The company recorded these payments as reductions to “Short-term debt” and “Deferred Compensation.” Refer to Note 3 for information regarding the non-cash effects of adopting FAS 143, “Accounting for Asset Retirement Obligations.”

ChevronTexaco separately manages businesses related to exploration and production; refining, marketing and transportation; and chemicals. “All Other” consists of the company’s interest in Dynegy, coal mining operations, power and gasification businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities and technology companies. The

company’s primary country of operation is the United States of America, its country of domicile. The remainder of the company’s operations is 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 and, in the 2002 periods, merger-related expenses, remain at the corporate level. After-tax segment income (loss) for the three- and nine-month periods ended September 30, 2003 and 2002, is presented in the following table:

Segment Assets. Segment assets do not include intercompany investments or intercompany receivables. “All Other” assets consist primarily of worldwide cash and marketable securities, real estate, information systems, the investment in Dynegy, coal mining operations, power and gasification businesses and technology companies. Segment assets at September 30, 2003, and year-end 2002 follow:

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

Sales from the transfer of products between segments are at prices that approximate market prices. Operating segment sales and other operating revenues, including internal transfers, for the three- and nine-month periods ended September 30, 2003 and 2002, are presented in the following table:

In connection with various reorganizations and restructurings across several businesses and corporate departments, the company recorded before-tax charges of $135 million ($86 million after tax) in the third quarter 2003 for estimated termination benefits for approximately 2,000 employees. A majority of the liability related to the global downstream business, including the effect of its reorganization along functional lines rather than the current geographic configuration. Substantially all of the employee reductions are expected to occur by early 2005.

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

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

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


(1)	2003 net income includes a charge of $323 million for the cumulative effect of changes in accounting principles.

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

Summarized financial information for CTC and its consolidated subsidiaries is presented as follows:

During the first quarter 2003, CTC’s paid-in capital increased by $18 million from additional capital contributions and settlements. There were no restrictions on CTC’s ability to pay dividends or make loans or advances at September 30, 2003.

Income tax expense before the cumulative effect of changes in accounting principles for the third quarter and nine months 2003 was $1.374 billion and $4.494 billion, respectively, compared with $866 million and $2.332 billion for the comparable periods in 2002. The effective tax rate for the third quarter 2003 was 41 percent. For the 2002 quarter, the income tax expense was applied to a before-tax loss of $38 million. For the year-to-date periods, the effective tax rates were 44 percent and 91 percent for 2003 and 2002, respectively. Excluding the effects of special items described in Note 2, the effective income tax rate for the comparative periods in 2003 and 2002 ranged from 43 to 45 percent. The effective tax rates for the 2003 periods were slightly less than the rates for the comparable 2002 periods as a result of a lower proportion of international taxable income, which is taxed at higher rates than U.S. taxable income.

In 2003 and 2002, the company had stock-based compensation plans. The company accounts for those plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The following table illustrates the effect on net income and earnings per share if the company had applied the fair-value recognition provisions of Financial Accounting Standards Board (FASB) Statement No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation:


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

Unocal Patent. Chevron, Texaco and four other oil companies (refiners) filed suit in 1995, contesting the validity of a patent (‘393’ patent) granted to Unocal Corporation (Unocal) for certain reformulated gasoline blends. ChevronTexaco sells reformulated gasolines in California in certain months of the year. In March 2000, the U.S. Court of Appeals for the Federal Circuit upheld a September 1998 District Court decision that Unocal’s patent was valid and enforceable and assessed damages of 5.75 cents per gallon for gasoline produced during the summer of 1996 which infringed on the claims of the patent. In February 2001, the U.S. Supreme Court concluded it would not review the lower court’s ruling, and the case was sent back to the District Court for an accounting of all infringing gasoline produced after August 1, 1996. The District Court ruled that the per-gallon damages awarded by the jury are limited to infringement that occurs in California only. Additionally, the U.S. Patent and Trademark Office (USPTO) granted three petitions by the refiners to re-examine the validity of Unocal’s ‘393’ patent and has twice rejected all of the claims in the ‘393’ patent. Those rejections have been appealed by Unocal to the USPTO Board of Appeals. The District Court judge requested further briefing and advised that she would not enter a final judgment in this case until the USPTO had completed its re-examination of the ‘393’ patent. During 2002 and 2003, the USPTO granted two petitions for reexamination of another Unocal patent, the ‘126’ patent. The USPTO has rejected the validity of the claims of the ‘126’ patent, which could affect a larger share of U.S. gasoline production. Separately, in March 2003, the Federal Trade Commission (FTC) filed a complaint against Unocal alleging that its conduct during the pendency of the patents was in violation of antitrust law. The complaint seeks to enjoin Unocal from collecting royalties on its patents, effectively rendering them unenforceable. Trial is set for December 2003.

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

MTBE. Another issue involving the company is the petroleum industry’s use of methyl tertiary butyl ether (MTBE) as a gasoline additive and its potential environmental impact through seepage into groundwater. Along with other oil companies, the company is a party to lawsuits and claims related to the use of the chemical MTBE in certain oxygenated gasolines. These actions may require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. ChevronTexaco has reduced the use of MTBE in gasoline it manufactures in the United States. California has directed that MTBE be phased out of the manufacturing process by the end of 2003, and the company intends to comply with this mandate. In the first quarter 2003, the company completed the conversion to marketing motor gasoline with ethanol as an oxygenate instead of MTBE in southern California, and will complete the changeover in northern California by the end of the year.

Income Taxes. The U.S. federal income tax liabilities have been settled through 1996 for ChevronTexaco Corporation (formerly Chevron Corporation), 1993 for ChevronTexaco Global Energy Inc. (formerly Caltex), and 1991 for Texaco Inc. The company’s California franchise tax liabilities have been settled through 1991 for Chevron and 1987 for Texaco.

Settlement of open tax years, as well as tax issues in other countries where the company conducts its business, 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. The company and its subsidiaries have certain other contingent liabilities with respect to guarantees, direct or indirect, of debt of affiliated companies or others and long-term unconditional purchase obligations and commitments, throughput agreements and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. Under the terms of the guarantee arrangements, generally the company would be required to perform should the affiliated company or third party fail to fulfill its obligations under the arrangements. In some cases, the guarantee arrangements have recourse provisions that would enable the company to recover any payments made under the terms of the guarantees from securities held of the guaranteed parties’ assets.

Indemnities. The company also provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell Oil Company and Saudi Refining Inc. in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover contingent general liabilities, certain contingent liabilities for specific incidents and liabilities associated with the Unocal patent litigation. The company would be required to perform should the indemnified liabilities become actual losses and could be required to make maximum future payments of $300 million. The company has paid approximately $28 million under these contingencies. There are no recourse provisions enabling recovery of any amounts from third parties nor are any assets held as collateral. Within five years of the February 2002 sale, at the

buyer’s option, the company also may be required to purchase certain assets from Shell Oil Company for their net book value, as determined at the time of the company’s purchase.

The company has also provided indemnities pertaining to the contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the periods of ChevronTexaco’s ownership interests in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 12, 2001. Claims relating to Equilon must be asserted no later than February 13, 2009, and claims relating to Motiva must be asserted no later than February 13, 2012. Under the terms of the indemnities, there is no maximum limit on the amount of potential future payments. The company has not recorded any liabilities for possible claims under these indemnities. The company holds no assets as collateral and has made no payments under the indemnities.

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

Minority Interests. The company has commitments related to preferred shares of subsidiary companies, which are accounted for as minority interest. Texaco Capital LLC, a wholly owned finance subsidiary, has issued $65 million of Deferred Preferred Shares, Series C. Dividends amounting to $59 million on Series C, at a rate of 7.17 percent compounded annually, will be paid at the redemption date of February 28, 2005, unless earlier redemption occurs. Early redemption may result upon the occurrence of certain specific events. Another subsidiary, MVP Production Inc., issued variable rate cumulative, voting preferred shares of $75 million owned by one minority holder. The shares were redeemed during the third quarter 2003.

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

Financial Instruments. The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodities and other derivatives activities, including forward exchange contracts and interest rate swaps. However, the results of operations and the financial position of certain equity affiliates may be affected by their business activities involving the use of derivative instruments.

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

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

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

Equity Redetermination. For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated oil and gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for ChevronTexaco’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills in 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 less than $200 million. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at more than $50 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

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

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

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

At issue is whether such mineral interest costs should be classified on the balance sheet as part of “Properties, plant and equipment” or as “Intangible assets” with related disclosures. The company will continue to classify these costs as “Properties, plant and equipment” and apportion them to expense in future periods under the company’s existing accounting policy until authoritative guidance is provided. For ChevronTexaco, the net book value of this category of mineral interests investment at September 30, 2003, was approximately $4 billion.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 amended ARB 51, “Consolidated Financial Statements,” and established standards for determining under what circumstances a variable interest entity (VIE) should be consolidated by its primary beneficiary. FIN 46 also requires disclosures about VIEs that the company is not required to consolidate but in which it has a significant variable interest. On October 10, 2003, the FASB issued FASB Staff Position 46-6, which deferred the effective date for implementation of FIN 46 to the first interim period ending after December 15, 2003. The company is continuing to assess the impact of FIN 46 on its consolidated financial statements.

Income (Loss) Before Changes in Accounting Principles by Major Operating Area

Net income for the third quarter of 2003 included a net gain of $14 million from special items. The net special items in the third quarter 2003 included a gain of $365 million related to the exchange of the company’s $1.5 billion investment in Dynegy convertible preferred stock for cash and other Dynegy securities, as well as net gains of $82 million from asset dispositions. Essentially offsetting these gains were special charges for asset impairments, including assets to be disposed of — $215 million, environmental remediation accruals — $132 million, and restructuring and reorganization costs — $86 million. Last year’s third quarter included charges of $1.549 billion related to the company’s Dynegy affiliate, $485 million for asset impairments and other asset revaluations, $48 million for environmental remediation costs and merger-related expenses of $73 million. These charges were partially offset by favorable tax adjustments of $14 million.

Net income for the first nine months of 2003 was $5.5 billion, compared with $228 million in the year-ago period. In addition to the third quarter 2003 net gain from special items, net income for the nine months 2003 included charges of $196 million for the cumulative effect of changes in accounting principles, mainly relating to a new accounting standard for asset retirement obligations, net charges of $117 million primarily for the write-down of assets in anticipation of their sale and $39 million for the company’s share of losses from asset sales and impairments by an international equity affiliate. Net income for the first nine months of 2002 included charges of $2.254 billion related to Dynegy, $485 million for asset impairments and other asset revaluations, $156 million for environmental remediation costs, the settlement of a litigation issue partially offset by favorable tax adjustments, and $278 million for merger-related expenses.

Earnings per share on a diluted basis for the 2003 quarter were $2.02, compared with a loss of $0.85 in last year’s quarter. The amount in 2003 included a benefit of $0.16 for the company’s share of a capital stock transaction of its Dynegy 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. For the 2002 quarter, earnings per share included $2.02 of charges for net special items.

For the nine-month periods, earnings per share on a diluted basis were $5.33 and $0.22 in 2003 and 2002, respectively. The amount in 2003 included a reduction of $0.32 for the effects of accounting-principle changes and net special charges, as well as the benefit of $0.16 related to the Dynegy capital stock transaction in the third quarter. For the 2002 nine months, the per-share effect of net charges for special items was $2.99.

Because of their nature and amount, the special items mentioned above are identified separately to help explain the changes in net income and segment income between periods, as well as to help distinguish the underlying trends for the company’s businesses. In the following discussions, the term “earnings” is defined as net income or segment income, before the cumulative effect of changes in accounting principles.

Earnings for exploration and production (upstream) operations in both the third quarter and nine months of 2003 benefited from strong crude oil and natural gas prices, which were higher than in the comparative 2002 periods. Partially offsetting the benefits of higher prices in 2003, as well as the favorable effect from lower net charges for special items in the 2003 period, were declines in oil-equivalent production of approximately 4 percent from the third quarter and nine months of 2002 and foreign currencies losses resulting from a weakening of the U.S. dollar.

For the refining, marketing and transportation (downstream) segment, profits of $181 million and $934 million for the third quarter and nine months 2003, respectively, primarily reflected a recovery from depressed levels in the corresponding 2002 periods, mainly as a result of significantly improved refined-product margins worldwide.

ChevronTexaco’s current and future earnings depend largely on the profitability of its upstream and downstream businesses. Overall earnings trends are typically less affected by results from the company’s commodity chemicals sector and other investments. In some reporting periods, net income can also be affected significantly by special items.

A key component of the company’s competitive position, particularly given its capital-intensive and commodity-based nature, is the ability to invest capital in projects that provide adequate financial returns and to manage operating expenses effectively. The company also continuously evaluates opportunities to dispose of assets that are not key to providing long-term value, or to acquire assets or operations complementary to its asset base to help sustain the company’s growth. Besides the asset-disposition plans announced to date in 2003, the company expects to finalize and communicate other asset-sale and restructuring plans during the remainder of the year and into 2004. Such plans could result in significant gains or losses in future periods.

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

Upstream. Changes in exploration and production earnings align most closely with industry price levels for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, weather-related damages and disruptions, competing fuel prices, and regional supply interruptions that may be caused by military conflicts or political uncertainty. For example, political and community unrest has disrupted the company’s production in the past, most recently in Nigeria and Venezuela. The company continues to monitor developments closely in the countries in which it operates. Additionally, the company’s production, particularly operations in the U.S. Gulf of Mexico, can be adversely affected by severe weather, including hurricanes. Longer-term trends in earnings for this segment are also a function of a range of factors in addition to price trends, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas reserves.

During 2002, industry price levels for crude oil trended upward from the $20 per-barrel level at the beginning of the year to about $30 in December. Prices fluctuated during the first nine months of 2003, but remained at significantly higher levels than the same 2002 period and were the major factors in this segment’s higher earnings in 2003. For the first nine months of 2003, the average spot price for West Texas Intermediate (WTI), a benchmark crude oil, was over $31 per barrel, compared with about $25 per barrel in the year-ago

period. The higher prices for crude oil in early 2003 in part reflected the geopolitical uncertainty in Iraq and Venezuela. Despite the conclusion of major hostilities in Iraq, the WTI price has remained around $30 per barrel on low inventory levels, production constraints by the Organization of Petroleum Exporting Countries (OPEC) and uncertainties about the timing of resumption of crude oil exports from Iraq. The average spot price for WTI crude oil in October was around $30 per barrel.

Benchmark prices for Henry Hub U.S. natural gas started 2002 in the low-$2 range per thousand cubic feet and also rose during the year to about the $5 level. In the first nine months of 2003, the benchmark natural gas price averaged nearly $6 thousand cubic feet, compared with about $3 per thousand cubic feet in the 2002 period. The higher U.S. natural gas prices were primarily attributable to the industry’s near-record low inventories. Natural gas inventories were replenished at a record setting rate during the third quarter largely due to modest supply growth, weak industrial demand and mild summer conditions dampening cooling consumption. At the end of the refill-cycle, inventories are expected to be slightly above average levels. In October, the Henry Hub price averaged about $4.70 per thousand cubic feet. Price movements near-term will depend in part on the level of demand during the winter heating season.

In the first nine months of 2003, the company’s worldwide oil-equivalent production was down about 4 percent from the year-ago period. The decrease was largely the result of lower output in the United States due to normal field declines and production deemed uneconomic to restore following storm damages in the Gulf of Mexico in last year’s second half. International oil-equivalent production was also down slightly — primarily the result of lower liquids production in the company’s Indonesian operations, due to the effect of higher prices on cost-oil recovery volumes under production-sharing arrangements and the expiration of a production-sharing agreement in the third quarter 2002.

Oil-equivalent production levels in future periods are uncertain, in part because of production quotas by OPEC and the potential for local civil unrest and changing geopolitics that could cause production disruptions. In Nigeria, approximately 45,000 barrels per day of the company’s net production capacity has been shut-in in certain onshore areas since March because of security concerns. It is possible that OPEC production constraints would limit the eventual resumption of a portion or all of this production.

Downstream. Refining, marketing and transportation earnings are closely tied to regional demand for refined products and the effect on industry refining and marketing margins. Other company-specific factors influencing the company’s profitability in this segment include the operating efficiencies of the refinery network, including any downtime due to planned maintenance, refinery upgrade projects or operating incidents.

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

Chemicals. Earnings of $29 million in the third quarter 2003 were up from the year-ago period. Nine-month profits of $66 million were about 10 percent lower. Depressed earnings levels in both years reflect excess supply conditions for the commodity chemicals industry that have kept product margins at low levels for a protracted period. Significant improvement in earnings is not expected in the near future.


	•	U.S. Gulf of Mexico — Early in the fourth quarter 2003, ChevronTexaco announced three new deepwater oil discoveries — Sturgis, Perseus and Saint Malo. Follow-up appraisal drilling is planned for each of the prospects. The company is the operator and holds a 50 percent working interest in both the Sturgis and Perseus prospects and holds a 12.5 percent interest in partner-operated Saint Malo. The company also announced that it had reached an agreement to acquire additional working interest


		and assume operatorship of the Blind Faith discovery. Under the terms of the agreement, ChevronTexaco will earn the right to operate Blind Faith with a 50 percent working interest.

	•	Australia — The Gorgon Joint Venture, in which the company is a 57 percent owner, received preliminary approval from the Western Australia state government to proceed with plans to construct a multibillion-dollar gas processing plant on Barrow Island. The decision represents a significant milestone in the company’s plans to commercialize its large natural gas resource base. The joint venture also announced an agreement with the China National Offshore Oil Corporation (CNOOC) in October to negotiate the sale and purchase of Gorgon liquefied gas to China. The agreement, which is subject to the completion of formal contracts, enables CNOOC to purchase an interest in the Gorgon gas development project.

	•	Nigeria — In October, ChevronTexaco announced successful results from the Aparo-3 appraisal well and the Nsiko-1 wildcat well in deepwater block OPL-249, where the company is entitled to a variable equity interest over the life of the field. The company also announced a significant extension of the Usan field discovery, located in deepwater block OPL-222, in which the company has a 30 percent interest. The drilling of the Usan-4 appraisal well confirmed the presence of commercial quantities of oil, as well as additional potential in previously untested reservoirs.

	•	Chad/Cameroon — The company’s first cargo of crude oil from landlocked fields in southern Chad was loaded at facilities offshore Cameroon for export to world markets early in the fourth quarter. The crude oil produced in Chad is transported over 600 miles by pipeline to a floating storage and offloading vessel located several miles offshore. Full production capacity of 225,000 barrels per day is targeted for early 2004. ChevronTexaco holds a 25 percent equity interest in the Chad-Cameroon Oil Development and Pipeline Project.

	•	Kazakhstan — The company’s 50-percent-owned affiliate, Tengizchevroil (TCO) reached agreement with the government of Kazakhstan late in the third quarter 2003 to expand operations at Tengiz. The agreement formalizes earlier understandings relating to the Second Generation Program and Sour Gas Injection Project. The two expansion projects are expected to increase Tengiz’s oil production capacity from the current rate of about 285,000 barrels per day to between 430,000 and 500,000 barrels per day in the second half of 2006. In a separate development, a 400-mile pipeline was completed, enabling production from the Karachaganak Field to be exported to world markets via the Caspian Pipeline system. Early in the fourth quarter 2003, the company also announced the sale of its interest in the North Buzachi oil and gas field.

	•	Global Gas — In October, the company announced plans for the construction of an estimated $650 million liquefied natural gas (LNG) receiving and regasification terminal offshore Baja California, Mexico. In the Gulf of Mexico, a decision is expected in the coming months on the company’s Port Pelican deepwater LNG facility permit application.

	•	Global Refining — The company completed the sale of its refinery in El Paso, Texas in August. In addition, plans were announced to convert the company’s refinery in Batangas, Philippines, into a finished-product import terminal. The terminal is expected to be operational by the end of this year.

Major Business Area. The following section presents the results of operations for the company’s business segments, as well as for the departments and companies managed at the corporate level. To aid in the understanding of changes in segment income between periods, the discussion, when applicable, may be in two parts — first on underlying trends, and second on special items that tended to obscure these trends. In the following discussions, the term “earnings” is defined as net income or segment income, before the cumulative effect of changes in accounting principles.

U.S. exploration and production income of $788 million in the third quarter increased $418 million from the 2002 period. Nearly one-half of the change related to the difference in the effect of special items. Other favorable effects between periods included higher crude oil and natural gas prices, mark-to-market adjustments for contracts accounted for as derivatives, and lower exploration expenses related to well write-offs. Partially offsetting these items were the effects of lower crude oil and natural gas production and higher depreciation, depletion and amortization expense. Year to date segment income of $2.1 billion was up from $1.2 billion in the year-ago period, mainly the result of higher prices for crude oil and natural gas, partially offset by lower oil-equivalent production and increased depreciation expense. The nine-month 2003 results also benefited from lower charges for special items, compared with the year-ago period.

The average liquids realization for the quarter was $26.09 per barrel, compared with $23.33 in the year-ago period. For the comparative nine-month periods, the average liquids realization of $26.83 was up 30 percent from $20.66. The average natural gas realization for the third quarter 2003 was $4.63 per thousand cubic feet, compared with $2.77 in the 2002 third quarter. Year-to-date, the average natural gas realization of $5.21 in 2003 nearly doubled the average sales price of $2.70 for the nine months last year.

Third quarter net oil-equivalent production of 917,000 barrels per day declined 9 percent from the 2002 period. For the comparative nine-month periods, production of 945,000 barrels per day in 2003 was down about 8 percent. Lower production from the year-ago comparative periods resulted primarily from normal field declines and the absence of about 10,000 to 15,000 barrels per day of oil-equivalent production the company deemed uneconomic to restore following storm damages in the Gulf of Mexico late last year. The net liquids component of production was down 7 percent to 561,000 barrels per day for the quarter and down 8 percent to 567,000 barrels per day for the nine-month period. Net natural gas production averaged 2.1 billion cubic feet per day in the 2003 third quarter, down 11 percent from the year-ago period. For the nine months of 2003, net natural gas production of nearly 2.3 billion cubic feet per day was 8 percent lower than the 2002 period.

The net special-item benefit of $9 million in the 2003 quarter included net gains of $46 million from property sales, which were partially offset by asset impairments of $37 million. For the nine months of 2003, the net special item charge of $49 million was composed of charges totaling $103 million — associated mainly with the write-down of assets in anticipation of sale — offsetting gains of $54 million from asset dispositions.

International exploration and production income increased $244 million from the year-ago quarter to $791 million, due mainly to higher crude oil and natural gas prices and lower special-item charges. Partially offsetting these benefits were adverse foreign currency changes. For the first nine months of 2003, income before the cumulative effect of the accounting change of $2.4 billion increased 13 percent from the year-ago period.

Net foreign currency losses of $24 million in the 2003 quarter primarily related to the weakening of the U.S. dollar against the currencies of Australia and the United Kingdom. Gains of $60 million in the 2002 quarter resulted from gains in several countries — particularly Argentina, Canada, Venezuela and the United Kingdom — that were partially offset by losses in Nigeria. For the year-to-date periods, currency losses were $187 million in 2003, compared with gains of $138 million in 2002. While the losses in the 2003 nine-month period reflected the weakening of the U.S. dollar, the gains in the 2002 period reflected significant gains in the first and second quarters attributable to the devaluation of the Argentine peso.

The average liquids realization for the quarter was $26.36 per barrel, up about 5 percent from last year’s quarter. For the nine-month periods, the average liquids realization of $26.66 per barrel in 2003, compared with $22.25 per barrel in 2002. The average natural gas realization for the third quarter 2003 was $2.55 per thousand cubic feet, compared with $2.06 in the 2002 quarter. For the first nine months of 2003, the average natural gas realization was $2.62, versus $2.07 in the corresponding 2002 period.

Net oil-equivalent production for the third quarter 2003 declined one percent, or 18,000 barrels per day, from the year-ago period. For nine months, net oil-equivalent production was down 2 percent from the corresponding 2002 period. Between quarters, the net liquids component declined 31,000 barrels per day to 1,215,000 barrels per day. For the nine-month periods, net liquids production of 1,242,000 barrels per day in 2003 was down about 4 percent. For both the third quarter and nine-month periods, the largest decrease occurred in Indonesia, down 31,000 barrels per day for the third quarter and 51,000 barrels per day for the nine-month period, respectively. The lower production related primarily to the effect of lower cost-oil recovery volumes under production-sharing terms and the expiration of a production sharing agreement in the third quarter 2002. Production was also lower in Kazakhstan as a result of scheduled maintenance. Besides new production in Chad, higher volumes were also produced in the United Kingdom and Venezuela. Net natural gas production of about 2.0 billion cubic feet per day in the third quarter of 2003 was up 4 percent. The largest production increases occurred in the Philippines, where production was increased to meet local demand, and in the United Kingdom. For the nine months, net natural gas production of nearly 2.1 billion cubic feet per day in 2003, compared with 1.9 billion cubic feet per day in 2002. The increase between the nine-month periods was primarily the result of higher output in Australia, Kazakhstan, the Philippines and the United Kingdom.

The net special-item charges of $10 million and $23 million in the 2003 third quarter and nine months, respectively, included impairment charges for the write-down of certain assets in advance of their sale, offset partly by gains from the sale of various Canadian properties. Special-item charges in 2002 were for asset impairments reflecting write-downs in quantities of proved oil and gas reserves for fields in Africa and Canada, and the effect of tax-law changes in the United Kingdom on prior years’ deferred tax balances.

U.S. refining, marketing and transportation earnings of $148 million improved from a loss of $79 million in the 2002 quarter. For the first nine months of 2003, earnings of $405 million compared with a loss of $263 million in the corresponding 2002 period. The primary reason for the improvement in both periods was a recovery in the industry’s refined-product margins.

The quarter’s average refined product sales price increased 4 percent to $40.43 per barrel. For the nine-month periods, the average refined product sales price of $40.78 in 2003 was up over 20 percent from $33.38 last year. Refined product sales volumes decreased 4 percent to 1,511,000 barrels per day in the third quarter and were 7 percent lower at 1,435,000 barrels per day in the first nine months of 2003. The reductions reflect weakened demand for gasoline, diesel and jet fuels, as well as lower sales under certain supply contracts. Branded gasoline sales volumes declined 2 percent from the year-ago quarter to 577,000 barrels per day. For the nine months, branded gasoline sales volumes of 559,000 barrels per day were 4 percent lower than the 2002 period.

Net special charges of $146 million in the third quarter and nine months 2003 included reserves for environmental remediation and employee severance costs associated with the global downstream restructuring and reorganization, which were partially offset by gains from asset sales. Special-item charges in the 2002 quarter were for the write-down of assets and environmental remediation costs. In addition, the nine-month 2002 period included special charges of $86 million for litigation and environmental remediation reserves.

International refining, marketing and transportation earnings increased to $33 million, compared with a $79 million loss in the year-ago quarter. Earnings of $529 million in the first nine months of 2003 were $467 million higher than in the year-ago period. The improvement in both periods primarily reflected stronger refined-product margins in most of the company’s operating areas.

Total refined product sales volumes of 2,243,000 barrels per day in the third quarter 2003 decreased 3 percent compared with last year’s quarter — reflecting lower demand for fuel oil in the European market and lower production during the planned maintenance and upgrade project at the Pembroke refinery in the United Kingdom. For the year-to-date periods, refined product sales volumes of 2,290,000 barrels per day in 2003 were about 4 percent higher than in the corresponding 2002 period. This improvement reflected an increase in sales of gasoline under supply contracts, improved demand for fuel oil and higher sales by the company’s equity affiliates.

Earnings in the 2003 quarter included foreign currency losses of $9 million, compared with gains of $9 million in 2002. Year-to-date foreign currency losses of $87 million compared with losses of $120 million in 2002.

Special items of $104 million in the third quarter 2003 included charges for the write-down of the Batangas refinery in the Philippines in advance of its conversion to a terminal facility, and employee severance benefits connected with the global downstream restructuring and reorganization. In addition to the third quarter special items, nine-month results included special charges of $85 million for the impairment of assets in anticipation of their sale and the company’s share of losses from an asset sale and asset impairment by an equity affiliate. The special item in 2002 was for a write-down of the company’s investment in its publicly traded Caltex Australia Limited affiliate to its estimated fair value at September 30, 2002.

Chemical operations earned $29 million, versus $22 million in the 2002 quarter. Profit improvements for the company’s 50 percent-owned Chevron Phillips Chemical Company LLC affiliate were partially offset by lower earnings for the Oronite subsidiary. For the nine month periods, 2003 earnings of $66 million were down from $73 million in 2002. Protracted weak demand for commodity chemicals and industry over-supply conditions continued to suppress earnings for this sector.

Earnings in the 2003 quarter included foreign currency gains of $3 million, compared with losses of $1 million in the 2002 quarter. Year-to-date foreign currency effects were gains of $13 million in 2003 and minimal in 2002.

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

Net segment income for the third quarter 2003 of $186 million, compared with net segment charges of $1.7 billion in the year-ago period. Special items in the 2003 quarter included a $365 million gain from the exchange of the company’s investment in Dynegy preferred stock for cash and other Dynegy securities. This benefit was partially offset by charges for asset write-downs of $84 million — mainly in the gasification business — and employee severance costs. Included in the 2002 results were special charges related to the company’s investment in Dynegy, its share of Dynegy’s loss from an asset disposition and merger-related expenses. These charges were partially offset by favorable tax adjustments. In addition to the impact of special items between quarters, net segment charges declined mainly as a result of higher earnings from Dynegy and power and gasification projects, and lower net corporate charges.

For the year-to-date periods, net segment charges before the cumulative-effect accounting adjustments were $143 million in 2003, compared with $2.9 billion in the nine months of 2002. In addition to the third quarter 2002 special charges, results for the first nine months of 2002 included special charges of $934 million related to the company’s investment in Dynegy, merger-related expenses, environmental remediation reserves and the company’s share of a write-down by Dynegy. Nine-month 2003 results also reflected lower interest expense, income taxes and other corporate charges, compared with the 2002 period.

For further information related to the company’s investment in Dynegy, please see “Information Relating to the Company’s Investment in Dynegy” on pages 9 to 10 and pages 31 to 32 of this Quarterly Report on Form 10-Q.

Explanations are provided below of variations between periods for certain income statement categories:

Sales and other operating revenues for the third quarter 2003 were $30.2 billion, up from $25.7 billion in last year’s quarter. For the nine months of 2003, sales and other operating revenues were $89.9 billion, compared with $71.7 billion in the 2002 nine months. Revenues increased in both 2003 periods on significantly higher prices for crude oil, natural gas and refined products.

Income (loss) from equity affiliates increased $616 million — from a loss of $329 million in the third quarter 2002 to income of $287 million in the third quarter 2003. For the nine-month period, income from equity affiliates was $767 million in 2003, compared with a loss of $136 million in the 2002 period. The third quarter of 2003 included net special charges for asset write-downs of $61 million, primarily in the gasification business, compared with $590 million for the company’s share of Dynegy’s write-downs and other adjustments, the company share of Dynegy losses from asset sales and a write-down of the company’s investment in its Caltex Australia Limited affiliate in the 2002 quarter. Excluding special items, earnings improved for a number of affiliates, including Dynegy and Chevron Phillips Chemical Company LLC.

For the nine-month periods, net special charges were $146 million and $777 million, for 2003 and 2002, respectively. Charges for nine months 2003 included the company’s share of losses from asset sales by an equity affiliate, an impairment of an investment in anticipation of sale, and other impairments of other investments. In the 2002 period, the special-item charges were attributable to Dynegy-related asset write-downs and losses from asset sales, and a write-down of the company’s investment in its Caltex Australia Limited affiliate. Excluding special items, the results of many affiliates improved in the nine-month period, including TCO and Dynegy.

See pages 9 to 10 and pages 31 to 32 for further information concerning the company’s investment in Dynegy.

Other income of $155 million in the 2003 quarter was up from $15 million in the corresponding 2002 quarter. For the nine-month periods, other income was $264 million in 2003, compared with $243 million last year. The quarterly improvement reflected higher net gains of $93 million from asset sales and a reduction of $42 million in foreign currency losses. The nine-month change was primarily attributable to higher net gains from asset sales partially offset by increased foreign currency losses.

Purchased crude oil and products costs of $18.0 billion in the third quarter 2003 were up from $14.9 billion in the 2002 quarter. For the nine-month periods, such costs were $53.6 billion in 2003, up 30 percent from $41.4 billion in 2002. The increase for the nine-month period was the result of significantly higher prices for crude oil, natural gas and refined products.

Operating, selling, general and administrative expenses of $3.5 billion in the third quarter 2003 were up from $3.2 billion in the 2002 period. The increase was primarily the result of higher transportation and employee-benefit costs. For the nine-month periods, such expenses increased $691 million in 2003. The increase between the nine-month periods was due mainly to higher transportation and shipping costs and increases in pension expense and other employee benefit expenses.

Exploration expenses were $130 million in the third quarter 2003, compared with $166 million in the 2002 quarter. For the nine-month periods, expenses of $432 million in 2003 increased $46 million from the corresponding 2002 period.

Depreciation, depletion and amortization expenses were $1.4 billion in the third quarter 2003, compared with $1.5 billion in the third quarter 2002. For the nine-month periods, expenses were $4.1 billion and $4.0 billion in 2003 and 2002, respectively.

Merger-related expenses of $111 million and $413 million were recorded in the 2002 quarter and nine months, respectively. None was recorded in 2003, reflecting the completion of merger integration activities last year.

Taxes other than on income were $4.4 billion in the third quarter 2003 and 2002, respectively. For the nine-month periods, taxes of $13.3 billion in 2003 were $975 million higher. The increase in 2003 primarily reflected the effect of the weakening U.S. dollar in 2003 on foreign-currency denominated duties in the company’s European downstream operations.

Interest and debt expense declined slightly between quarterly periods. For the nine-month periods, such expense was $363 million in 2003, compared with $424 million. The decrease in the 2003 period was the result of lower average debt balances and lower average interest rates.

Income tax expense before the cumulative effect of changes in accounting principles for the third quarter and nine months 2003 was $1.374 billion and $4.494 billion, respectively, compared with $866 million and $2.332 billion for the comparable periods in 2002. The effective tax rate for the third quarter 2003 was 41 percent. For the 2002 quarter, the income tax expense was applied to a before-tax loss of $38 million. For the year-to-date periods, the effective tax rates were 44 percent and 91 percent for 2003 and 2002, respectively. Excluding the effects of special items described in Note 2, the effective income tax rate for the comparative periods in 2003 and 2002 ranged from 43 to 45 percent. The effective tax rates for the 2003 periods were slightly less than the rates for the comparable 2002 periods as a result of a lower proportion of international taxable income, which is taxed at higher rates than U.S. taxable income

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

In addition to the $365 million gain recorded in income in the third quarter 2003, the company also recorded $170 million directly to “Retained Earnings,” which represented the company’s approximate 26 percent equity share of a gain recorded by Dynegy in connection with the Series B exchange transaction. Under the accounting rules applicable to preferred stock redemptions, the company increased its earnings per share in the third quarter 2003 by $0.16 for the effect of the $170 million recorded directly to “Retained Earnings.”


(1)	Includes equity in affiliates.

(2)	MBPD = thousand barrels per day; MMCFPD = million cubic feet per day; Bbl. = barrel; MCF = thousand cubic feet.

(3)	Represents total field production under the Boscan operating service agreement in Venezuela.

(4)	Excludes Equilon and Motiva.

(5)	Includes branded and unbranded gasoline.

Cash and cash equivalents and marketable securities totaled $5.2 billion at September 30, 2003 — up from $3.8 billion at year-end 2002. Cash provided by operating activities was about $9.8 billion in the first nine months of 2003, compared with $6.7 billion in the year-ago period, reflecting significantly improved earnings. Cash provided by asset sales was $491 million in the first nine months of 2003, compared with $2.3 billion in the corresponding 2002 period. The 2002 period included proceeds from the sale of the company’s investments in Equilon and Motiva. Cash provided by operating activities in the first nine months of 2003 generated sufficient funds for the company’s capital and exploratory program and the payment of dividends to stockholders, as well as contributing significantly to a net reduction of $3.0 billion in debt levels and the increase in cash and cash equivalents and marketable securities.

Dividends. During the first nine months of 2003, the company paid dividends of $2.3 billion to common stockholders. On October 31, 2003, ChevronTexaco declared a quarterly dividend of 73 cents per share, unchanged from the preceding quarter.

Debt and Capital Lease Obligations. ChevronTexaco’s total debt and capital lease obligations were $13.3 billion at September 30, 2003, down from $16.3 billion at year-end 2002. In the first nine months of 2003, net repayments of $3 billion in short-term debt and $1 billion in long-term debt and other financing obligations were partially offset by proceeds of $1 billion from the issuance of new long-term debt. New issuances of long-term debt during 2003 included $750 million of 3.375 percent ChevronTexaco Capital Company notes due in February 2008, $265 million of new Philippine debt, and $17 million of individually smaller issues. Proceeds from the ChevronTexaco Capital Company note issue were used to retire commercial paper. Repayments of long-term debt included $665 million of Texaco Capital Inc. bonds, $143 million of Philippine debt, $110 million of ChevronTexaco Corporation 8.11 percent notes, $107 million of Nigerian debt and $54 million of individually smaller issues. Additionally, a $210 million payment was made to the Republic of Kazakhstan relating to the company’s 1993 acquisition of its interest in the TCO joint venture. Also included in the reduction in the company’s long-term debt levels was a non-cash reduction of $50 million of ESOP debt.

The company’s debt due within 12 months, consisting primarily of commercial paper and the current portion of long-term debt, totaled $6.1 billion at September 30, 2003, down from $9.5 billion at December 31, 2002. Of this total short-term debt, $4.2 billion and $4.1 billion were reclassified to long-term at September 30, 2003, and December 31, 2002, respectively. Settlement of these obligations was not expected to require the use of working capital in 2003, 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 management believes appropriate.

At the end of the third quarter 2003, ChevronTexaco had $4.2 billion in committed credit facilities with various major banks, which permit the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and also can be used for general credit requirements. No borrowings were outstanding under these facilities at September 30, 2003. In addition, ChevronTexaco had three existing effective shelf registrations on file with the SEC that together would permit additional registered offerings up to an aggregate $2.0 billion of debt securities.

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

The company’s future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. The company believes it has substantial borrowing capacity to meet unanticipated cash requirements, and 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 to continue paying the common stock dividend and maintain the company’s high-quality debt ratings.

Current Ratio — current assets divided by current liabilities. The current ratio was 1.2 at September 30, 2003, compared with 0.9 at December 31, 2002, and benefited from significantly lower short-term debt. However, the current ratio was adversely affected in all periods presented by including inventories valued on a LIFO basis, which at year-end 2002 were lower than replacement costs, based on average acquisition costs during the year, by nearly $1.6 billion. The company does not consider inventory valuation to affect its liquidity.

Debt Ratio — total debt divided by total debt plus equity. This ratio was 27 percent at September 30, 2003, compared with 34 percent at year-end 2002, reflecting the reduction in overall debt levels and increase in stockholders’ equity in the first nine months of 2003.

Minority Interests. The company has commitments related to preferred shares of subsidiary companies, which are accounted for as minority interest. Texaco Capital LLC, a wholly owned finance subsidiary, has issued $65 million of Deferred Preferred Shares, Series C. Dividends amounting to $59 million on Series C, at a rate of 7.17 percent compounded annually, will be paid at the redemption date of February 28, 2005, unless earlier redemption occurs. Early redemption may result upon the occurrence of certain specific events. Another subsidiary, MVP Production Inc., redeemed $75 million of variable rate cumulative, voting preferred shares on their redemption date of September 30, 2003, after electing not to exercise its option to extend the redemption date until 2008.

Dynegy. In August, the company completed an agreement with Dynegy to exchange its $1.5 billion face value of Series B Preferred Dynegy Stock for $225 million in cash, $225 million face value of Junior Unsecured Subordinated Notes due 2016 and $400 million face value of Series C Convertible Preferred Stock. See pages 9 to 10 and pages 31 to 32 for further information on this restructuring and other matters relating to the company’s investment in Dynegy.

Pension Obligations. The company anticipates no near-term funding of its major pension plans will be required under regulatory minimum funding rules however, the company periodically evaluates the economic benefits of making voluntary funding contributions to its pension plans in advance of those that would otherwise be required by regulation. In August 2003, the company made a voluntary funding contribution of approximately $150 million to its main U.S. pension plan. Additional voluntary funding to this plan and others may be made in the near future if favorable economic circumstances warrant such contributions.

Capital and exploratory expenditures, including the company’s share of affiliates’ expenditures, were $5.1 billion in the first nine months of 2003, compared with $6.6 billion in the corresponding 2002 period. Expenditures for international exploration and production projects were $2.9 billion — 56 percent of the total expenditures — reflecting the company’s continued emphasis on increasing international oil and gas production. In the first nine months of 2002, capital expenditures included more than $400 million for the acquisition of assets associated with the Captain Field in the North Sea that were previously leased, an approximate $200 million additional investment in the company’s Dynegy affiliate and an additional investment of $125 million in the Chevron Phillips Chemical Company affiliate.

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

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

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 less than $200 million. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at more than $50 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

Information about market risks for the three and nine months ended September 30, 2003 does not differ materially from that discussed under Item 7A of ChevronTexaco’s Annual Report on Form 10-K for 2002.

ChevronTexaco Corporation’s Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the company’s “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of the end of the period covered by this report, have concluded that as of the end of the period covered by this report, the company’s disclosure controls and procedures were adequate and designed to ensure 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.

During the quarter ended September 30, 2003, 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.

Chevron Products Company, a division of Chevron U.S.A. Inc, has agreed to pay $126,600 to the Bay Area Air Quality Management District (“BAAQMD”) and $25,000 to Contra Costa County in settlement of alleged violations of the BAAQMD’s air regulations at the Company’s Richmond, California refinery.

Chevron U.S.A. has agreed to reduce air emissions over the next eight years for an estimated cost of $275 million at five U.S. petroleum refineries, located in Richmond and El Segundo, Calif.; Pascagoula, Miss.; Salt Lake City, Utah; and Kapolei, Hawaii. Pursuant to a settlement with the U.S. Environmental Protection Agency for alleged violations of federal and state air and release reporting regulations, the Company will pay a $3.5 million civil penalty and also undertake supplemental environmental projects. Also joining in the settlement are the states of Hawaii, Mississippi, and Utah, and the BAAQMD.


	(1) On October 31, 2003, ChevronTexaco furnished a copy of a press release announcing unaudited third quarter 2003 net income of $1.975 billion on a Form 8-K dated October 31, 2003.

Pursuant to the requirements 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.


		CHEVRONTEXACO CORPORATION


	(Registrant)

	/s/ S. J. CROWE

	S. J. Crowe, Vice President and Comptroller
	(Principal Accounting Officer and
	Duly Authorized Officer)


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

		For the quarterly period ended September 30, 2003

or

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


Delaware		94-0890210
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)
6001 Bollinger Canyon Road, San Ramon, California		94583
(Address of principal executive offices)		(Zip Code)


Class	Outstanding as of September 30, 2003
Common stock, $.75 par value		1,068,958,980


		Page
		No.

	Cautionary Statements Relevant to Forward-Looking Information for the Purpose of “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		2
PART I FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements Consolidated Statement of Income for the three months and nine months ended September 30, 2003 and 2002		3
	Consolidated Statement of Comprehensive Income for the three months and nine months ended September 30, 2003 and 2002		4
	Consolidated Balance Sheet at September 30, 2003, and December 31, 2002		5
	Consolidated Statement of Cash Flows for the nine months ended September 30, 2003 and 2002		6
	Notes to Consolidated Financial Statements		7-21
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22-38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		39
Item 4.	Controls and Procedures		39
PART II OTHER INFORMATION
Item 1.	Legal Proceedings		40
Item 6.	Listing of Exhibits and Reports on Form 8-K		40
Signature			41
Exhibits: Computation of Ratio of Earnings to Fixed Charges			43
Rule 13a-14(a)/15d-14(a) Certifications			44-45
Section 1350 Certifications			46-47



		Three Months Ended					Nine Months Ended
		September 30,					September 30,

		2003		2002			2003			2002


		(Millions of dollars, except per-share amounts)
Revenues and Other Income
Sales and other operating revenues(1)		$	30,163	$	25,681		$	89,900		$	71,748
Income (loss) from equity affiliates			287		(329	)		767			(136	)
Gain from exchange of Dynegy securities			365		—			365			—
Other income			155		15			264			243

	Total Revenues and Other Income		30,970		25,367			91,296			71,855

Costs and Other Deductions
Purchased crude oil and products			18,007		14,871			53,619			41,378
Operating expenses			2,321		2,118			6,041			5,569
Selling, general and administrative expenses			1,197		1,032			3,267			3,048
Exploration expenses			130		166			432			386
Depreciation, depletion and amortization			1,409		1,514			4,062			3,960
Write-down of investment in Dynegy Inc.			—		1,094			—			1,796
Merger-related expenses			—		111			—			413
Taxes other than on income(1)			4,418		4,369			13,261			12,286
Interest and debt expense			115		117			363			424
Minority interest			24		13			66			35

	Total Costs and Other Deductions		27,621		25,405			81,111			69,295

Income (Loss) Before Income Tax Expense			3,349		(38	)		10,185			2,560
Income Tax Expense			1,374		866			4,494			2,332

Income (Loss) Before Cumulative Effect of Changes in Accounting Principles			1,975		(904	)		5,691			228
Cumulative effect of changes in accounting principles, net of tax			—		—			(196	)		—

Net Income (Loss)		$	1,975	$	(904	)	$	5,495		$	228


Per Share of Common Stock:
	Income (Loss) Before Cumulative Effect of Changes in Accounting Principles(2)
		— Basic	$	2.02	$	(0.85	)	$	5.52	$	0.22
		— Diluted	$	2.02	$	(0.85	)	$	5.51	$	0.22
	Net Income (Loss)(2)
		— Basic	$	2.02	$	(0.85	)	$	5.34	$	0.22
		— Diluted	$	2.02	$	(0.85	)	$	5.33	$	0.22
	Dividends		$	0.73	$	0.70		$	2.13	$	2.10
	Weighted Average Number of Shares Outstanding (000s)
		— Basic		1,062,718		1,061,633			1,062,333		1,060,721
		— Diluted		1,064,090		1,063,662			1,063,801		1,062,660



(1) Includes consumer excise taxes:	$	1,814	$	1,782	$	5,270	$	5,221
(2) The amounts in 2003 include a benefit of $0.16 for the company’s share of a capital stock transaction of its Dynegy Inc. affiliate, which under the applicable accounting rules was recorded directly to the company’s retained earnings and not included in net income for the period.


				At September 30,			At December 31,
				2003			2002

				(Unaudited)

				(Millions of dollars)
ASSETS
Cash and cash equivalents				$	4,383		$	2,957
Marketable securities					844			824
Accounts and notes receivable					9,623			9,385
Inventories:
	Crude oil and petroleum products				2,070			2,019
	Chemicals				158			193
	Materials, supplies and other				486			551

		Total inventories			2,714			2,763
Prepaid expenses and other current assets					1,589			1,847

		Total Current Assets			19,153			17,776
Long-term receivables					1,412			1,338
Investments and advances					12,431			11,097
Properties, plant and equipment, at cost					107,590			105,231
Less: accumulated depreciation, depletion and amortization					61,674			61,076

		Properties, plant and equipment, net			45,916			44,155
Deferred charges and other assets					2,399			2,993

			Total Assets	$	81,311		$	77,359

LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt				$	1,853		$	5,358
Accounts payable					8,067			8,455
Accrued liabilities					2,891			3,364
Federal and other taxes on income					2,270			1,626
Other taxes payable					1,180			1,073

		Total Current Liabilities			16,261			19,876
Long-term debt					11,168			10,666
Capital lease obligations					243			245
Deferred credits and other noncurrent obligations					7,745			4,474
Noncurrent deferred income taxes					5,693			5,619
Reserves for employee benefit plans					4,690			4,572
Minority interests					267			303

		Total Liabilities			46,067			45,755

Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued)					—			—
Common stock (authorized 4,000,000,000 shares, $.75 par value, 1,137,021,057 shares issued)					853			853
Capital in excess of par value					4,850			4,833
Retained earnings					34,352			30,942
Accumulated other comprehensive loss					(884	)		(998	)
Deferred compensation and benefit plan trust					(601	)		(652	)
Treasury stock, at cost (68,062,077 and 68,884,416 shares at September 30, 2003 and December 31, 2002, respectively)					(3,326	)		(3,374	)

		Total Stockholders’ Equity			35,244			31,604

			Total Liabilities and Stockholders’ Equity	$	81,311		$	77,359


	Amount

	(Millions of dollars
	before-tax)
Balance at June 30, 2003	$	23
Additions		135
Payments		(4	)

Balance at September 30, 2003	$	154


Note 8.	Summarized Financial Data — Chevron U.S.A. Inc.


Note 9.	Summarized Financial Data — Chevron Transport Corporation


Item 2.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*


	*Information Relating to the Company’s Investment in Dynegy*


Item 3.	*Quantitative and Qualitative Disclosures About Market Risk*


(4)		Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the company 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 company and its subsidiaries on a consolidated basis. A copy of any such instrument will be furnished to the Commission upon request.
(12.1)		Computation of Ratio of Earnings to Fixed Charges
(31.1)		Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer
(31.2)		Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer
(32.1)		Section 1350 Certification by the company’s Chief Executive Officer
(32.2)		Section 1350 Certification by the company’s Chief Financial Officer


Item 1.	*Consolidated Financial Statements*



			Three Months Ended						Nine Months Ended
			September 30,						September 30,

			2003			2002			2003			2002


			(Millions of dollars)
Exploration and Production
	United States		$	3,007		$	2,183		$	10,209		$	6,776
	International			3,770			3,349			11,521			10,278

		Sub-total		6,777			5,532			21,730			17,054
	Intersegment Elimination — United States			(1,463	)		(1,229	)		(5,325	)		(3,317	)
	Intersegment Elimination — International			(2,005	)		(2,066	)		(5,918	)		(6,272	)

		Total		3,309			2,237			10,487			7,465

Refining, Marketing and Transportation
	United States			12,590			10,667			36,756			27,552
	International			13,771			12,389			41,209			35,599

		Sub-total		26,361			23,056			77,965			63,151
	Intersegment Elimination — United States			(55	)		(76	)		(143	)		(155	)
	Intersegment Elimination — International			48			(10	)		15			(142	)

		Total		26,354			22,970			77,837			62,854

Chemicals
	United States			119			111			341			325
	International			188			185			576			539

		Sub-total		307			296			917			864
	Intersegment Elimination — United States			(37	)		(29	)		(100	)		(78	)
	Intersegment Elimination — International			(23	)		(21	)		(62	)		(55	)

		Total		247			246			755			731

All Other


Note 7.	Restructuring and Reorganization Costs


Note 10.	Income Taxes


Exhibit
Number		Description

(4)		Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the company 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 company and its subsidiaries on a consolidated basis. A copy of any such instrument will be furnished to the Commission upon request.
(12.1)		Computation of Ratio of Earnings to Fixed Charges.
(31.1)		Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer
(31.2)		Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer
(32.1)		Section 1350 Certification by the company’s Chief Executive Officer
(32.2)		Section 1350 Certification by the company’s Chief Financial Officer