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 management’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, 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; 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 crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; potential disruption or interruption of the company’s production or manufacturing facilities due to war, accidents, political events, civil unrest or severe weather; potential liability for remedial actions under existing or future environmental laws or regulations; 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 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.


(2)	Per-share amounts and weighted average number of shares outstanding in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.

(3)	The amounts in 2003 include a benefit of $0.08 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.


*	Share amounts and capital in excess of par value have been restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.

The accompanying consolidated financial statements of ChevronTexaco Corporation and its subsidiaries (the company) have not been audited by independent accountants. 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 items described in Note 2, and the cumulative effect of changes in accounting principles in 2003, described in Note 16.

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 2003 Annual Report on Form 10-K.

The results for the three- and nine-month periods ended September 30, 2004, are not necessarily indicative of future financial results.

Net income for the third quarter 2004 was $3.2 billion. Included in this amount were special-item gains of $486 million related to the sale of nonstrategic upstream assets. Income from discontinued operations was $265 million. Information for discontinued operations is discussed in Note 4.

Net income for the third quarter 2003 was $2 billion. Net special gains included in net income were $14 million. This net amount included a gain of $365 million associated with the exchange of securities with the company’s Dynegy Inc. affiliate, which was substantially offset by charges for environmental remediation, net losses on asset sales and charges for business restructuring and reorganization. Income from discontinued operations was $14 million.

Net income for the first nine months of 2004 was $9.9 billion. Net special gains totaled $1.0 billion. Besides the third quarter special gain mentioned above, this amount also included a gain of $585 million related to the sale of nonstrategic upstream assets in western Canada. Income from discontinued operations was $313 million.

Net income for the first nine months of 2003 was $5.5 billion. Special items reduced earnings in this period by $142 million. Besides the amounts mentioned for the third quarter, the nine months included $156 million of additional losses related to asset dispositions. Net income for the period also included a charge of $196 million for the cumulative effect of changes in accounting principles, mainly relating to a new accounting standard for asset retirement obligations. The cumulative effect of changes in accounting principles is discussed in Note 16. Income from discontinued operations was $51 million.

Foreign currency effects reduced earnings by $29 million and $31 million in the third quarter of 2004 and 2003, respectively. For the first nine months of 2004 and 2003, foreign currency effects reduced earnings by $27 million and $233 million, respectively.

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

At September 30, 2004, and December 31, 2003, the company classified $369 million and $1.1 billion, respectively, of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. Assets in this category at the end of the third quarter were upstream properties and an office building in

the United States. In October 2004, $123 million of the held-for-sale upstream properties were withdrawn from sale and reclassified as “held and used.” The adjustment to depreciation and depletion expense in the fourth quarter for the period the assets were held for sale will be immaterial. Assets otherwise classified as held-for-sale at September 30, 2004, are expected to be disposed of within approximately one year.

Summarized income statement information relating to discontinued operations is as follows:

Included in the third quarter 2004 after-tax amount were gains totaling $252 million related to the sale of a Canadian natural-gas processing business, a wholly owned subsidiary in the Democratic Republic of the Congo and certain producing properties in the Gulf of Mexico.

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

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

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

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

The 2004 “Net Cash Provided by Operating Activities” included a $388 million “Decrease in other deferred charges” and a decrease of the same amount in “Other” related to balance sheet netting of certain pension-related asset and liability accounts, in accordance with the requirements of Financial Accounting Standards Board (FASB) Statement No. 87, “Employers’ Accounting for Pensions.”

The “Net (purchases) sales of treasury shares” in 2004 included share repurchases of $1.35 billion related to the company’s common stock repurchase program, which were partially offset by the issuance of shares for the exercise of stock options.

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


*	2003 included $210 million deferred payment related to the 1993 acquisition of the company’s interest in the Tengizchevroil joint venture.

Although each subsidiary of ChevronTexaco is responsible for its own affairs, ChevronTexaco Corporation manages its investments in these subsidiaries and their affiliates. For this purpose, the investments are grouped as follows: upstream — exploration and production; downstream — refining, marketing and transportation; chemicals; and all other. The first three of these groupings represent the company’s “reportable segments” and “operating segments” as defined in FAS 131, “Disclosures about Segments of an Enterprise and Related Information.”

The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) (terms as defined in

FAS 131). The CODM is the company’s Executive Committee, a committee of senior officers that includes the chief executive officer, and which in turn reports to the Board of Directors of ChevronTexaco Corporation.

The operating segments represent components of the company as described in FAS 131 terms that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM to make decisions about resources to be allocated to the segment and to assess its performance; and (c) for which discrete financial information is available.

Segment managers for the reportable segments are directly accountable to, and maintain regular contact with, the company’s CODM to discuss the segment’s operating activities and financial performance. The CODM approves annual capital and exploratory budgets at the reportable segment level, as well as approves capital and exploratory funding for major projects and approves major changes to the annual capital and exploratory budgets. However, business-unit managers within the operating segments are directly responsible for decisions relating to project implementation and all other matters connected with daily operations. Company officers who are members of the Executive Committee also have individual management responsibilities and participate on other committees for purposes other than acting as the CODM.

“All Other” activities include the company’s interest in Dynegy Inc. (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. Other components of the company’s operations are reported as “International” (outside the United States).

Segment Earnings. The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All Other.” After-tax segment income from continuing operations for the three-month and nine-month periods ended September 30, 2004 and 2003, 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, cash equivalents and marketable securities, real estate, information systems, the company’s investment in Dynegy, coal mining operations, power and gasification businesses, technology companies and assets of the corporate administrative functions. Segment assets at September 30, 2004, and December 31, 2003 follow:

Segment Sales and Other Operating Revenues. Revenues for the upstream 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 downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, kerosene, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the transportation and trading of crude oil and refined products. Revenues for the chemicals segment are derived primarily from the manufacture and sale of additives for lubricants and fuel. “All Other” activities include revenues from coal mining operations, 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, 2004 and 2003, 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 $258 million ($146 million after tax) during the third and fourth quarters of 2003 for estimated termination benefits for approximately 4,500 employees. Nearly half of the liability related to the downstream segment. 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 2004 is summarized in the table below:

At the beginning of 2004, a $100 million liability remained for employee severance charges recorded in 2002 and 2001 associated with the merger between Chevron Corporation and Texaco Inc. The balance related primarily to deferred payment options elected by certain employees who terminated before the end of 2003. About $80 million of the liability was paid during the first nine months of 2004.

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 regulated 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 2004 and 2003, ChevronTexaco implemented legal reorganizations in which certain ChevronTexaco subsidiaries transferred assets to or under CUSA and other ChevronTexaco companies were merged with and into CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the table below gives retroactive effect to the reorganizations in a manner similar to a pooling of interests, with all periods presented as if the companies had always been combined and the reorganizations had occurred on January 1, 2003. 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 reorganizations actually occurred on January 1, 2003.


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


*	Includes assets held for sale of $369 million and $1,052 million at September 30, 2004 and December 31, 2003, respectively.

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:

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at September 30, 2004.

Taxes on income from continuing operations for the third quarter and nine months of 2004 were $1.9 billion and $5.6 billion, respectively, compared with $1.4 billion and $4.4 billion for the comparable periods in 2003. The associated effective tax rates for the 2004 and 2003 third quarters were 39 percent and 41 percent, respectively. For the year-to-date periods, the effective tax rates were 37 percent and 44 percent, respectively.

The effective tax rate for the three-month period of 2004 benefited mainly from additional favorable corporate consolidated tax effects compared with the corresponding period in 2003. The effective tax rate for the nine-month period of 2004 benefited from changes in the income tax laws for certain international operations, a change in the mix of international upstream earnings occurring in countries with different tax rates and favorable corporate consolidated tax effects.

At September 30, 2004, 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 fair market value is estimated using the Black-Scholes option-pricing model.

(2)	Per-share amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.

(3)	The amounts in 2003 include a benefit of $0.08 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.

The company has defined benefit pension plans for many employees and provides for certain health care and life insurance plans for some active and qualifying retired employees. The company typically funds only those defined benefit plans where legal funding is required. In the United States this includes all qualified tax-exempt plans subject to the Employee Retirement Income Security Act of 1974 (ERISA) minimum funding standard. The company does not typically fund domestic nonqualified tax-exempt pension plans that are not subject to legal funding requirements because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.

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


*	Includes costs for U.S. and international other postretirement benefit plans. Obligations for plans outside the U.S. are not significant relative to the company’s total other postretirement benefit obligation.

At the end of 2003, the company estimated that contributions to employee pension plans during 2004 would total $785 million (composed of $585 million for the U.S. plans and $200 million for the international plans). As a result of additional studies to review the full year’s appropriate funding levels, through September 30, 2004, a total of $1.2 billion had been contributed (all except $65 million to the U.S. plans). In the third quarter 2004, the company funded $624 million ($603 million and $21 million to the U.S. and international plans, respectively). Contributions for the fourth quarter of 2004 are estimated at $100 million. The company will continue to review funding levels during the fourth quarter and may contribute an amount that differs from the current estimate. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became law. The Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care plans that provide a benefit that is at least actuarially equivalent to Medicare

Part D. In May 2004, the FASB issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2). One U.S. subsidiary was deemed at least actuarially equivalent and eligible for the federal subsidy. The effect on the company’s postretirement benefit obligation and the associated annual expense was de minimis.

During the third quarter, the company contributed $50 million to its other postretirement benefit plans. For the first nine months of 2004, the company contributed a total of $152 million and expects to contribute about $55 million in the fourth quarter.

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.

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

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

During 2002 and 2003, the USPTO granted two petitions for re-examination of another Unocal patent, the ‘126’ patent. The USPTO has twice rejected the validity of the claims of the ‘126’ patent, which could affect a larger share of U.S. gasoline production. Separately, in March 2003, the Federal Trade Commission (FTC) filed a complaint against Unocal alleging that its conduct during the pendency of the patents was in violation of antitrust law. In November 2003, the Administrative Law Judge dismissed the complaint brought by the FTC. The FTC appealed the decision and oral arguments were heard before the FTC in early March 2004. On July 7, 2004, the FTC reversed the November 2003 decision of the Administrative Law Judge, reinstated the complaint and remanded the case to the Administrative Law Judge for further consideration of the allegations in the complaint. The FTC trial commenced on October 19, 2004.

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 U.S. refining and marketing operations, although presently indeterminable, could be material. ChevronTexaco has been accruing in the normal course of business any future estimated liability for potential infringement of the ‘393’ patent covered by the 1998 trial court’s ruling.

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

MTBE. Another issue involving the company is the petroleum industry’s use of methyl tertiary butyl ether (MTBE) as a gasoline additive and its potential environmental impact through seepage into groundwater.

Along with other oil companies, the company is a party to more than 70 lawsuits and claims related to the use of the chemical MTBE in certain oxygenated gasolines. Resolution of these actions may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future.

The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. Currently, there are no detectable levels of MTBE in gasoline manufactured by the company in the United States.

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 assets provided as collateral.

Indemnities. The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell Oil Company (Shell) and Saudi Refining Inc. in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover general contingent liabilities, including those associated with the Unocal patent litigation. The company would be required to perform should the indemnified liabilities become actual losses and could be required to make maximum future payments of $300 million. The company has paid approximately $28 million under these contingencies and has disputed approximately $35 million in claims submitted by Shell under these indemnities. Arbitration of this dispute is scheduled for the fourth quarter 2004. The indemnities contain 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 Shell’s option, the company also may be required to purchase certain assets for their net book value, as determined at the time of the company’s purchase. Those assets consist of 12 separate lubricant facilities, two of which were tendered to and purchased by the company in late 2003 for a minor amount. The company has executed its right to have Shell’s put right expire as to one of the original facilities.

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

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

Other Commitments. The company has commitments related to preferred shares of subsidiary companies. Texaco Capital LLC, a wholly owned finance subsidiary, has issued $71 million of Deferred Preferred Shares, Series C (Series C). Dividends amounting to $64 million on Series C, at a rate of 7.17 percent compounded annually, will be paid at the redemption date of February 2005, unless earlier redemption occurs. Early redemption is required upon the occurrence of certain specific events, which the company does not anticipate will occur.

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

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

The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates, including the United States. As has occurred in the past, actions could be taken by host governments to increase public ownership of the company’s partially- or wholly owned businesses or assets, 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, acts of violence or strained relations between a host government and the company or other governments may affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results, and are carefully considered by management when evaluating the level of current and future activity in such countries.

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

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 crude oil and natural 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” 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 was whether such mineral interest costs should be classified on the balance sheet as part of “Properties, plant and equipment” or as “Intangible assets.” In FASB Staff Position No. FAS 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil-and Gas-Producing Entities”, the FASB Staff concluded that disclosures for crude oil and natural gas production companies are based on the requirements in FASB Statement No. 19 (FAS 19), “Financial Accounting and Reporting by Oil and Gas Producing Companies,” rather than FAS 142. The company will continue to classify these costs as “Properties, plant and equipment” in accordance with FAS 19.

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. In December 2003, the FASB issued FIN 46-R, which not only included amendments to FIN 46, but also required application of the interpretation to all affected entities no later than March 31, 2004 for calendar-year reporting companies. Prior to this requirement, companies were required to apply the interpretation to special-purpose entities by December 31, 2003. The full adoption of the interpretation as of March 31, 2004, including the requirements relating to special-purpose entities, did not have a material impact on the company’s results of operations, financial position or liquidity.

Refer to Note 12, beginning on page 16, for discussion related to the company’s implementation of FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.”

The SEC has issued several comment letters to companies in the oil and gas industry related to the accounting for suspended exploratory wells, particularly for those suspended under certain circumstances for more than one year.

The company’s accounting policy in this regard is to capitalize the cost of exploratory wells pending determination of whether the wells found proved reserves. Costs of wells that find proved reserves remain capitalized. Costs also are capitalized for wells that find commercially producible reserves that cannot be classified as proved, pending one or more of the following: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory wells that are under way or firmly planned, and (3) securing final regulatory approvals for development. Otherwise, well costs are expensed if a determination as to whether proved reserves were found cannot be made within one year following completion of drilling. All other exploratory well costs are expensed.

This topic was discussed at the September 2004 meeting of the Emerging Issues Task Force (EITF) as Issue 04-9, “Accounting for Suspended Well Costs” (EITF 04-9). The discussion centered on whether certain circumstances would permit the continued capitalization of the costs for an exploratory well beyond one year in the absence of plans for another exploratory well. The outcome of the September 2004 EITF meeting was agreement between the Task Force and the FASB that the circumstances outlined were inconsistent with the provisions in FASB Statement No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (FAS 19), and an amendment of FAS 19 would be required to formally adopt this view. For this reason, the Task Force agreed to remove the issue from the EITF agenda and requested that the FASB consider an amendment to FAS 19 to address the issue. Further, the Task Force recommended that the FASB amend FAS 19 to permit continued capitalization of suspended exploratory well costs if an exploratory well had found reserves and additional exploratory wells were not necessary to justify a major capital expenditure, as long as two conditions had been met: (a) the well had found a sufficient quantity of reserves to justify its completion as a producing well, assuming the required capital expenditures would be made, and (b) the company was making sufficient progress assessing and pursuing the reserves, including the economic and operating viability of the project.

The company will monitor the upcoming deliberations of the FASB on this matter and the possible implications, if any, to its accounting policy and the capitalized amounts for its suspended exploratory wells.

The company adopted FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143), effective January 1, 2003. This accounting standard applies to the fair value of a liability for an asset retirement obligation that is recorded when there is a legal obligation associated with the retirement of tangible long-lived assets and the liability can be reasonably estimated. FAS 143 primarily affects the company’s accounting for crude oil and natural gas producing assets and differs in several respects from previous accounting under FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.”

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,” $2.6 billion; “Accrued liabilities,” $115 million; and, “Deferred credits and other noncurrent obligations,” $2.7 billion. “Noncurrent deferred income taxes” decreased by $21 million.

Upon adoption, no significant asset retirement obligations associated with any legal obligations to retire refining, marketing and transportation (downstream) and chemical long-lived assets generally were recognized, as indeterminate settlement dates for the asset retirements prevented estimation of the fair value of the associated retirement obligation. 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.

Also in the first quarter 2003, the company recorded an after-tax gain of $4 million for its share of the Dynegy affiliate’s cumulative effect of adoption of Emerging Issue Task Force Consensus No. 02-3, “Issues

Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” effective January 1, 2003.

In October 2004, Congress passed the American Job Creation Act of 2004, which includes some tax relief provisions. The company is currently assessing the effects of the act.

Net income for the third quarter 2004 was $3.2 billion ($1.51 per share — diluted). The amount included special gains of $486 million ($0.23 per share — diluted) related to the sale of nonstrategic upstream assets. Income from discontinued operations was $265 million ($0.13 per share — diluted) relating to certain assets that were classified as discontinued operations because of their sale. Refer to Note 4 on pages 7 and 8 for a discussion of the rules for classifying assets as discontinued operations.

Net income for the 2003 third quarter was $2 billion ($1.01 per share — diluted), which included special-item gains of $365 million ($0.17 per share — diluted) related to the exchange of the company’s investment in Dynegy securities and net gains of $82 million ($0.04 per share — diluted) from asset dispositions. Nearly offsetting these gains were special-item charges for asset impairments of $215 million ($0.10 per share — diluted), environmental remediation accruals of $132 million ($0.06 per share — diluted) and restructuring and reorganization costs of $86 million ($0.04 per share — diluted).

For the first nine months of 2004, net income was $9.9 billion ($4.65 per share — diluted). Besides the third quarter items mentioned above, the first nine months included a special gain of $585 million ($0.28 per share — diluted) related to the sale of upstream assets in western Canada and a special charge of $55 million ($0.03 per share — diluted) for an adverse litigation ruling. Also included was a one-time benefit of approximately $250 million ($0.12 per share — diluted) associated with changes in income tax laws for certain international operations. Income from discontinued operations was $313 million ($0.15 per share — diluted) for the first nine months of 2004.

For the first nine months of 2003, net income was $5.5 billion ($2.66 per share — diluted). In addition to the third quarter items, results also included charges of $196 million ($0.09 per share — diluted) for the cumulative effect of changes in accounting principles, net charges of $117 million ($0.05 per share — diluted) primarily for the write-down of assets in anticipation of their sale and a charge of $39 million ($0.02 per share — diluted) for the company’s share of losses from asset sales by an equity affiliate. Income from discontinued operations was $51 million in the year-ago period ($0.03 per share — diluted). Refer to Note 16 for a discussion of the cumulative effect of changes in accounting principles.

The special items mentioned above are identified separately because of their nature and amount to help explain the changes in net income and segment income between periods and 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.

Upstream earnings in the third quarter 2004, including income from discontinued operations, were $2.6 billion, compared with $1.6 billion a year earlier. The 2004 period included nearly $0.5 billion of gains from nonstrategic asset sales. The earnings improvement otherwise was primarily the result of higher prices for crude oil and natural gas. For the comparative nine-month periods, upstream earnings increased $2.7 billion. Besides higher oil and gas prices, the 2004 period also benefited from gains of over $1 billion from asset sales and $0.2 billion from changes in income tax laws for certain international operations. Oil and gas production was lower in both the three- and nine-month periods.

With respect to product prices in the comparative periods, the U.S. average realization for crude oil and natural gas liquids increased nearly 40 percent between quarters to more than $36 per barrel. The increase was 23 percent in the nine-month period to nearly $33 per barrel. Internationally, the average price increased 43 percent to approximately $38 between quarters and increased 24 percent to $33 per barrel for the nine months.

Average U.S. natural gas sales prices in the third quarter 2004 increased 14 percent to $5.28 per thousand cubic feet compared with the third quarter 2003. Internationally, the average natural gas price increased about 2 percent to $2.59 in the comparative period. For the comparative nine-month period, the U.S. price increased about 3 percent to $5.37, while international prices were marginally lower.

Worldwide net oil-equivalent production in 2004, including volumes produced from oil sands and production under an operating service agreement, declined approximately 6 percent and 4 percent from the corresponding three-and nine-month periods of 2003. About two-thirds of the decline between quarters was associated with properties that were sold. Most of the decline otherwise resulted from the shut-down of certain producing operations in the Gulf of Mexico late in the quarter as a result of storms, and the effect of higher prices on the calculation of cost-recovery volumes under certain production-sharing contracts. For the comparable nine-month periods, approximately 65 percent of the decline was due to property sales.

Refer to pages 29 through 31 for a further discussion of upstream results in 2004 and 2003.

Downstream earnings were $490 million and $2.2 billion in the third quarter and nine months of 2004, respectively, up $309 million and $1.2 billion from the comparable periods in 2003. Earnings in 2004 benefited mainly from higher average industry margins for refined products, which resulted mainly from higher demand in most of the areas in which the company operates. Refer to pages 31 through 32 for a further discussion of downstream results in 2004 and 2003.

ChevronTexaco’s current and future earnings depend largely on the profitability of its upstream and downstream business segments. 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-item gains or charges.

The company’s long-term financial position, particularly given the capital-intensive and commodity-based nature of the industry, is closely associated with the company’s ability to invest in projects that provide adequate financial returns and to manage operating expenses effectively. The company also continues to evaluate opportunities to dispose of assets that are not key to providing sufficient long-term value, or to acquire assets or operations complementary to its asset base to help sustain the company’s growth. In addition to the asset-disposition and restructuring plans announced in 2003 and under way in 2004, other such plans may occur in future periods and result in significant gains or losses.

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, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damages and disruptions, competing fuel prices, and regional supply interruptions that may be caused by military conflicts, civil unrest or political uncertainty. The company monitors developments closely in the countries in which it operates.

Longer-term trends in earnings for this segment are also a function of other factors besides price fluctuations, including changes in the company’s crude oil and natural gas production levels and the company’s ability to find or acquire and efficiently produce crude oil and natural gas reserves. Most of the company’s overall capital investment is in its upstream businesses, particularly outside the United States. Investments in upstream projects oftentimes are made well in advance of the start of the associated crude oil and natural gas production.

During 2003, industry price levels for West Texas Intermediate (WTI), a benchmark crude oil, averaged about $31 per barrel. Prices trended upward during the first nine months of 2004 and remained at higher levels than the corresponding period in 2003. For the first nine months of 2004, the average spot price for WTI was more than $39 per barrel, compared with about $31 per barrel in the year-ago period. In the third quarter 2004, the average spot price for WTI was nearly $44 per barrel. WTI prices continued to rise in October 2004, averaging about $53 per barrel. These relatively high industry prices reflected increased demand from higher economic growth, particularly in Asia and the United States, the heightened level of geopolitical uncertainty in many areas of the world, supply concerns in the Middle East and other key producing regions and shut-in production in the U.S. Gulf Coast resulting from several hurricanes and tropical storms.

U.S. Benchmark prices for Henry Hub natural gas averaged nearly $5.50 per thousand cubic feet for 2003. In the first nine months of 2004, the U.S. benchmark natural gas price averaged $5.76 per thousand cubic feet, compared with $5.80 in the first nine months of 2003. Near-term natural gas price movements will depend in part on the level of demand during the winter heating season in the United States and the adequacy of production and storage levels to meet that demand.

As compared with the supply and demand factors in the United States and the resultant trend in the Henry Hub benchmark prices, certain other regions of the world in which the company operates have significantly different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices for the company’s production of natural gas. (Refer to page 36 for the company’s average natural gas prices for the U.S. and international regions.) Additionally, excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the United States and other markets because of lack of infrastructure and the difficulties in transporting natural gas.

To help address this regional imbalance between supply and demand for natural gas, ChevronTexaco and other companies in the industry are planning increased investment in long-term projects in areas of excess supply to install infrastructure to produce and liquefy natural gas for transport by tanker and investment to regasify the product in markets where demand is strong and supplies are not as plentiful. Due to the significance of the overall investment in these long-term projects, the natural gas sales prices in the areas of excess supply (before the natural gas is transferred to a company-owned or third-party processing facility) are expected to remain well below sales prices for natural gas that is produced much nearer to areas of high demand and which can be transported in existing natural gas pipeline networks (as in the United States).

In the first nine months of 2004, the company’s net worldwide oil-equivalent production, including volumes produced from oil sands and production under an operating service agreement, declined about 4 percent from the year-ago period. The decrease was largely the result of lower production in the United States due to normal field declines and the result of property sales. International oil-equivalent production remained essentially unchanged between periods.

The level of oil-equivalent production in future periods is uncertain, in part because of production quotas by OPEC and the potential for local civil unrest and changing geopolitics that could cause production disruptions. Approximately 25 percent of the company’s net oil-equivalent production in the first nine months of 2004, including net barrels from oil sands and production under an operating service agreement, was in the OPEC-member countries of Indonesia, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. Although the company’s production level during the first nine months of 2004 was not constrained in these areas by OPEC quotas, future production could be affected by OPEC-imposed limitations. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production.

In certain onshore areas of Nigeria, approximately 45,000 barrels per day of the company’s net production capacity has been shut-in since March 2003 because of security concerns and damage to production facilities. The company has adopted a phased plan to restore these operations and has taken initial steps to determine the extent of damage and secure the properties. The company has begun initial production-resumption efforts in certain areas. As a result of Hurricane Ivan in the Gulf of Mexico in September 2004, production in the fourth quarter is expected to be 50,000 — 60,000 barrels per day lower than it otherwise would have been. The time to restore all production-related facilities in this area is uncertain.

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

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

Downstream earnings improved in the third quarter and first nine months of 2004 primarily from improved demand and higher average refined product margins for the industry in most of the company’s operating areas. Overall margins in the United States in the third quarter 2004 declined from the same quarter in 2003 and from the first-half 2004. Industry margins may be volatile in the future, depending primarily on price movements for crude oil feedstocks, demand for product, inventory levels, refinery maintenance and mishaps, and other factors.

Chemicals. Earnings of $106 million in the third quarter 2004 were up from the year-ago period. Nine-month profits of $239 million increased $173 million from the previous year. Earnings for the company’s Oronite subsidiary improved on higher margins for lubricant additives in both periods. Earnings for the

50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate increased on higher prices for commodity chemicals and higher affiliate income.


	•	North America — Completion of the sale of approximately 180 producing properties in the United States and a Canadian natural-gas processing business in the third quarter with proceeds of approximately $1.1 billion and $200 million, respectively. These divestments were part of plans announced in 2003 to dispose of assets that did not provide sufficient long-term value and to improve the overall competitive performance and operating efficiency of the company’s exploration and production portfolio. Additionally, in the Gulf of Mexico, a potentially significant deepwater crude oil discovery was announced in September at the Jack Prospect in Walker Ridge Block 759, where the company holds a 50 percent working interest.

	•	Australia — Announcement of a significant natural gas discovery at the Wheatstone-1 well located offshore in Western Australia, in August, where the company holds a 100 percent interest.

	•	China — Announcement of initial crude oil production from the BZ 25-1 Field, located in Bohai Bay, where ChevronTexaco holds a 16.2 percent interest.

	•	Democratic Republic of the Congo — Completion of the sale of the company’s wholly owned subsidiary, Muanda International Oil Company (MIOC), in the Democratic Republic of the Congo (DRC).

	•	Nigeria — Announcement of a significant crude oil discovery at the Usan 5 well in the Oil Prospecting License (OPL) 222, near the earlier Usan 4 discovery. ChevronTexaco holds a 30 percent interest in OPL 222.

	•	Russia — Signing of a six-month memorandum of understanding with OAO Gazprom to jointly undertake feasibility studies for the possible implementation of projects in Russia and the United States. This represents a possible opportunity to participate in the development of the vast natural gas and crude oil resource base in Russia and to develop a partnership with Russia’s largest natural gas producer.

	•	Southern Africa — Announcement of a significant discovery in the deepwater area between the Republics of Angola and Congo at the Lianzi-1 exploration well. The discovery, in the shared 14K/A-IMI Unit, is located in the same area as the previous Block 14 deepwater crude oil discoveries at Landana and Tombua in Angola. ChevronTexaco is the operator of the Block 14/A-IMI Unit and holds a 31 percent interest.

	•	United Kingdom — Production of first crude oil from the 21 percent-owned Alba Extreme South Phase 2 Project. The Alba Field is located in Block 16/26, northeast of Aberdeen.

	•	Venezuela — Completion of construction of the Hamaca project’s crude oil upgrading facility, which will enable an increase from a current production level of 120,000 barrels per day to a design capacity of 190,000 barrels per day. Initial processing from the upgrader began in October. ChevronTexaco holds a 30 percent interest in the project. Also in the region, the company announced successful exploration drilling results at the 60 percent-owned and operated offshore Plataforma Deltana Loran 2X well.


	•	Asset Dispositions — Continuation of the marketing and sale of approximately 1,500 service station sites, with dispositions totaling more than 1,100 sites from the program’s inception in early 2003 through the third quarter of 2004.

	•	U.S. Marketing — Resumption of marketing gasoline under the Texaco retail brand in the United States in early July. By the end of October, the company was supplying more than 800 Texaco retail sites in the Southeast and plans to supply 1,000 sites by the end of 2004.


	•	Common Stock Dividends and Stock Repurchase Program — In July, the company announced a 10 percent increase in its quarterly common stock dividend, which was immediately followed by a 2-for-1 stock split in the form of a stock dividend. In connection with a targeted $5 billion stock repurchase program initiated April 1, 2004, the company purchased 28,275,000 shares in the open market for $1.35 billion through September. Purchases during October increased the total shares acquired to 30,620,000 for $1.48 billion. The repurchase program is in effect for a period up to three years from the April 2004 start-up.

Major Business Areas. The following section presents the results of operations for the company’s business segments, as well as for the departments and companies managed at the corporate level. (Refer to Note 6 beginning on page 9 related to a discussion of the company’s “reportable segments,” as defined in FAS 131, “Disclosures about Segments of an Enterprise and Related Information.”) To aid in the understanding of changes in segment income between periods, the discussion, when applicable, may be in two parts — first on underlying trends, and second on special-item gains and charges 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 was $1.2 billion in the third quarter, up $376 million from the 2003 period. Results included special gains of $279 million from the sale of nonstrategic assets. The improvement otherwise was primarily from higher prices for crude oil and natural gas. For the nine months, segment income was $3 billion, or $867 million higher than a year earlier. This period likewise benefited from higher prices and gains from property sales.

The average liquids realization for the third quarter was $36.26 per barrel, an increase of nearly 40 percent from $26.09 in the year-ago period. For the comparative nine months, the average liquids

realization of $32.99 was up 23 percent from $26.83. The average natural gas realization for the third quarter 2004 was $5.28 per thousand cubic feet, compared with $4.63 in the 2003 quarter. For the first nine months of 2004, the average natural gas realization was $5.37, compared with $5.21 in 2003.

Oil and gas production was lower in both the three- and nine-month periods and adversely affected earnings. Net oil-equivalent production declined 13 percent between quarterly periods to 801,000 barrels per day. Excluding declines of about 30,000 barrels per day from property sales and 18,000 barrels per day from the third quarter storms, net oil-equivalent production declined about 7 percent. For the comparative nine-month periods, oil-equivalent production declined 10 percent to 848,000 barrels per day. Absent the effects of property sales and storms, the decline in net oil-equivalent production was 8 percent. Besides the effect of property sales and the storms in third quarter 2004, normal field declines also contributed to the lower production in both periods, the effects of which were only partially offset by increased and first-time production from various fields.

The net liquids component of oil-equivalent production was down 11 percent to 499,000 barrels per day for the quarter and down 8 percent to 522,000 barrels per day for the nine-months. Excluding the effects of property sales and storms, third quarter 2004 and nine-month net liquids production declined 6 percent and 5 percent, respectively, from the year-ago periods. Net natural gas production in the 2004 quarter averaged 1.8 billion cubic feet per day, down approximately 15 percent from the 2003 period. Nine-month production was 2.0 billion cubic feet per day, down about 14 percent from the nine months of 2003. Absent the effects of property sales and shut-downs related to storms, net natural gas production declined 9 percent from the 2003 quarter and 11 percent from the nine months a year ago.

Besides the third quarter 2004 special-item gains, the nine-month period included a special charge of $55 million due to an adverse litigation matter. Included in the nine months of 2003 were net special charges of $49 million composed of charges totaling $103 million, mainly for the write-down of assets in anticipation of sale, partially offset by gains of $54 million from asset dispositions.

International exploration and production income increased $634 million from the year-ago quarter to $1.4 billion, primarily the result of higher average prices for crude oil and special gains of $207 million from the sale of nonstrategic assets in Canada and the Democratic Republic of the Congo. Net foreign exchange effects lowered earnings $57 million in the 2004 third quarter from exchange-rate movements, primarily in Canada. Segment income for the first nine months increased $2.1 billion from the year-ago period. In addition to the third quarter 2004 items, nine-month results included a special gain of $585 million from the sale of producing properties in western Canada and a one-time benefit of $208 million related to changes in certain income tax laws.

The average liquids realization for the third quarter 2004 was $37.75 per barrel, an increase of 43 percent from last year’s quarter. For the first nine months of 2004, average liquids realization was $33.11 per barrel compared with $26.66 per barrel in the year-ago period. The average natural gas realization for the third quarter 2004 was $2.59 per thousand cubic feet, compared with $2.55 in the 2003 quarter. For the first nine months of 2004, average natural gas realization was $2.61 per thousand cubic feet, and was essentially unchanged from the comparable year-ago period.

Net oil-equivalent production of 1.6 million barrels per day in the third quarter 2004 — including other produced volumes of 144,000 net barrels per day from oil sands and production under an operating service agreement — declined about 2 percent from the year-ago period. Excluding the lower production associated with properties sold since last year’s third quarter and reduced volumes associated with cost-recovery provisions of certain production sharing agreements, net oil-equivalent production increased nearly 4 percent, primarily from new liquids production in Chad and higher liquids production in Kazakhstan.

The net liquids component of oil-equivalent production for the third quarter 2004 decreased less than 2 percent to 1.3 million barrels per day. Net natural gas production was down slightly to 1.9 billion cubic feet per day. Excluding the effects of asset sales and the declines in cost-recovery volumes, liquids production increased 49,000 barrels per day and natural gas production was higher by 81 million cubic feet per day. On this basis, the increase in liquids production resulted primarily from higher production in Chad and Kazakhstan. Natural gas production was higher in a number of countries including Denmark, Colombia and Trinidad and Tobago. Countries with lower production included Canada, the United Kingdom and the Philippines.

For the first nine months of 2004, net oil-equivalent production of 1.7 million barrels per day — including other produced volumes of 142,000 net barrels per day from oil sands and production under an operating service agreement — was essentially unchanged from the year-ago period. Excluding the effect of property sales and lower cost-recovery volumes under certain production sharing agreements, net oil-equivalent production increased approximately 3 percent primarily from new liquids production in Chad and higher production in Kazakhstan.

Net liquids production averaged more than 1.3 million barrels per day during the first nine months of 2004, including other produced volumes from oil sands and production under an operating service agreement, and was essentially unchanged from 2003. Excluding property sales and lower cost-recovery volumes under certain production sharing agreements, net liquids production increased 42,000 barrels per day to just under 1.4 million barrels per day. Net natural gas production was up marginally between periods. Excluding the effect of asset sales, net natural gas production increased nearly 4 percent, as higher production in Denmark, Trinidad and Tobago and Colombia partially offset declines in Canada and the United Kingdom.

U.S. downstream earnings of $96 million declined $52 million from the 2003 quarter, which included special charges of $146 million. Refined-product margins were lower in the 2004 period, particularly on the West Coast. These lower margins also reflected the shutdown of the company’s refinery in Pascagoula, Mississippi, late in the quarter as a result of Hurricane Ivan, which required the company to make additional purchases from third parties to fulfill sales requirements. The refinery shutdown occurred during a period of otherwise strong industry refining margins in the Gulf Coast region. The period also included charges of $47 million for environmental remediation costs. For the first nine months of 2004, earnings were $889 million,

Refined-product sales volumes increased about 3 percent to 1,553,000 barrels per day in the third quarter, and were 6 percent higher in the nine-month period at 1,521,000 barrels per day. The increase between periods was primarily from higher sales of gasoline, diesel fuel and fuel oil. Branded gasoline sales volumes increased 2 percent from the year-ago quarter to 588,000 barrels per day. The sales improvement partially reflected the reintroduction of the Texaco brand in the Southeast. For the nine months, branded gasoline sales volumes were 565,000 barrels per day, about 1 percent higher than the comparative 2003 period.

In 2003, the net special charges of $146 million were for reserves for environmental remediation and employee severance costs, with a partial offset from asset-sale gains.

International refining, marketing and transportation segment income of $394 million in the third quarter 2004 increased $361 million from the year earlier, which included special charges of $104 million. Earnings were $756 million higher for the first nine months of 2004, which included special charges of $189 million. The improvement otherwise resulted mainly from higher margins for refined products in most of the company’s operating areas and improved earnings from equity affiliates.

Total refined-product sales volumes of nearly 2.4 million barrels per day in the 2004 quarter increased 6 percent. For the nine months, refined-product sales volumes of about 2.4 million barrels per day were 5 percent higher than in the corresponding 2003 period. The improvement for both periods primarily resulted from increased sales of jet fuel and gasoline and the company’s increased ownership in Singapore Refining Company.

The special charges of $104 million in the 2003 quarter included a write-down associated with the conversion of the Batangas Refinery in the Philippines to a terminal facility and employee severance costs connected with the downstream restructuring and reorganization. In addition to the third quarter special items, nine-month results included special charges of $46 million for the impairment of assets in anticipation of their sale and $39 million for the company’s share of losses from asset sales by an equity affiliate.

Chemical operations earned $106 million in the third quarter of 2004, compared with $29 million in the 2003 quarter. For the nine-month periods, earnings increased $173 million. For both periods, results for the company’s Oronite subsidiary improved on higher overall sales volumes and margins for lubricant additives. Earnings for the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate increased as the result of increased commodity chemical sales volumes and higher equity-affiliate income.

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 income before the cumulative effect of changes in accounting principles was $16 million in the third quarter of 2004, compared with $186 million in the corresponding 2003 period. Excluding the effects of special gains, income increased $95 million. The change primarily reflected benefits in the 2004 period for corporate consolidated tax effects, higher interest income and lower interest expense. Partially offsetting these benefits were an additional prior period impairment charge associated with Dynegy’s sale of Illinois Power Company assets, environmental charges and an increase in other corporate charges. For the comparative nine-month periods, similar benefits occurred from corporate consolidated tax effects, higher interest income and lower interest expense.

Special items in the year-ago quarter included a $365 million gain from the exchange of the company’s investment in Dynegy preferred stock for cash and other Dynegy securities, the benefit of which was partially offset by charges for asset write-downs, mainly in the gasification business, and employee severance costs.

For further information related to the company’s investment in Dynegy, please see “Information Relating to the Company’s Investment in Dynegy” beginning on page 34.

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

Sales and other operating revenues for the third quarter 2004 were $39.6 billion, up from $30 billion in last year’s quarter. For the first nine months of 2004, sales and operating revenues were $109 billion, up from $90 billion in the 2003 period. Revenues increased mainly on higher prices for crude oil and refined products worldwide.

Income from equity affiliates increased $326 million to $612 million in the third quarter 2004. For the nine-month period, income from equity affiliates increased approximately $1 billion to $1.8 billion. The increases were primarily the result of improved earnings from CPChem, Caspian Pipeline Consortium, Tengizchevroil and downstream affiliates in the Asia-Pacific area. Third quarter 2003 included net special charges of $61 million primarily related to write-downs in the gasification business. For the 2003 nine-month period, special charges were $146 million and included a loss from asset sales and the impairment of an investment in an equity affiliate.

Other income of $505 million was up from $148 million in the 2003 third quarter. For the nine-month periods, other income was $1.6 billion, compared to $242 million last year. The third quarter and nine-month periods of 2004 included net gains from the sale of certain upstream assets.

Purchased crude oil and products costs of $25.6 billion in the third quarter 2004 were up from $18 billion in the 2003 quarter. For the nine-month period, such costs were $68.1 billion, up from $53.4 billion in the

Operating, selling, general and administrative expenses of $3.8 billion in the third quarter 2004 were up from $3.4 billion in the year-ago quarter. For the nine-month periods, such expenses were $10.2 billion, compared to $9.3 billion last year. For the quarter and nine-month periods, the increases included costs for environmental remediation, chartering of crude-oil tankers and other transportation expenses.

Exploration expenses were $173 million in the third quarter 2004, compared with $127 million in the third quarter 2003. Amounts were higher for international operations, primarily for seismic costs and expenses associated with evaluating the feasibility of different project alternatives. For the nine-month periods, exploration expenses decreased about $7 million.

Depreciation, depletion and amortization expenses were $1.2 billion in the third quarter 2004, compared with $1.4 billion in the third quarter 2003. For the nine-month periods, expenses were $3.7 billion and $4 billion in 2004 and 2003, respectively. The 2003 third quarter included special charges of $184 million primarily for the write-down of assets in anticipation of sale and the write-down associated with the conversion of the Batangas Refinery in the Philippines to a terminal facility. The nine-month 2003 period also included special charges of $102 million for the write-down of assets in anticipation of their sale.

Taxes other than on income were $4.9 billion and $4.4 billion in the third quarter of 2004 and 2003, respectively. For the nine-month periods, expenses were $14.6 billion and $13.3 billion in 2004 and 2003, respectively. The increase in 2004 primarily reflected the weakened U.S. dollar effect on foreign-currency denominated duties in the company’s European downstream operations.

Interest and debt expense decreased $8 million to $107 million in the 2004 third quarter and decreased $69 million to $294 million in the nine-month period. The lower amounts in both periods primarily reflected lower average debt balances.

Income tax expense related to continuing operations for the third quarter and first nine months of 2004 was $1.9 billion and $5.6 billion, respectively, compared with $1.4 billion and $4.4 billion for the comparable periods in 2003. The associated effective tax rates for the 2004 and 2003 third quarters were 39 percent and 41 percent, respectively. For the corresponding year-to-date periods, the effective tax rates were 37 percent and 44 percent, respectively.

The effective tax rate for the third quarter 2004 benefited mainly from corporate consolidated tax effects. The effective tax rate for the nine months 2004 benefited from changes in the income tax laws for certain international operations and a change in the mix of international upstream earnings occurring in countries with different tax rates.

ChevronTexaco owns an approximate 26 percent equity interest in the common stock of Dynegy — an energy merchant engaged in power generation, natural gas liquids processing and marketing, and regulated energy delivery. The company also holds investments in Dynegy notes and preferred stock.

Investment in Dynegy Common Stock. At September 30, 2004, the carrying value of the company’s investment in Dynegy common stock was approximately $100 million. This amount was about $400 million below the company’s proportionate interest in Dynegy’s underlying net assets. This difference resulted from write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value that were deemed to be other than temporary. The approximate $400 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 recognize a portion of the difference between these allocated values and Dynegy’s historical book values.

Investment in Dynegy Notes and Preferred Stock. The face value of the company’s investment in the Dynegy Junior Notes at September 30, 2004, was $132 million. On October 1, 2004, full payment was

received, for which an associated after-tax gain of approximately $32 million will be recorded in the fourth quarter. After-tax gains of $4 million and $18 million were recorded in the first half and third quarter 2004, respectively, for earlier payments on the Junior Notes.

The face value of the company’s investment in the Dynegy Series C preferred stock at September 30, 2004, was $400 million. The stock is accounted for at its fair value, which was estimated to be $375 million at September 30, 2004. Future temporary changes in the estimated fair values of the preferred stock will be reported in “Other comprehensive income.” However, if any future decline in fair value is deemed to be other than temporary, a charge against income in the period would be recorded. Dividends payable on the preferred stock are recognized in income each period.

Cash and cash equivalents and marketable securities totaled $11 billion at September 30, 2004, up from $5.3 billion at year-end 2003. Cash provided by operating activities was $11.1 billion in the first nine months of 2004 and was net of $1.2 billion contributed to certain of the company’s pension plans during the period. Cash provided by operating activities in the first nine months of 2003 was $9.8 billion and was net of $236 million for pension plan contributions. Operating activities in the first nine months of 2004 generated sufficient funds for the company’s capital and exploratory program and for the payment of dividends to stockholders.

Dividends. During the first nine months of 2004, the company paid dividends of $2.4 billion to common stockholders. Refer to Note 3 on page 7 for information related to the company’s two-for-one stock split announced in July 2004 and page 29 for additional information on the company’s quarterly stock dividend increase.

Debt and Capital Lease Obligations. ChevronTexaco’s total debt and capital lease obligations were $11.9 billion at September 30, 2004, down from $12.6 billion at year-end 2003. In the third quarter 2004, $300 million 6 percent Texaco Capital Inc. bonds, due June 2005, were retired. Other repayments of long-term debt in 2004 included $120 million 8.11 percent notes and $265 million in Philippine debt. On October 1, 2004, the company redeemed $500 million 6.625% bonds at maturity.

The company’s debt due within 12 months, consisting primarily of commercial paper and the current portion of long-term debt, totaled $5.8 billion at September 30, 2004, down from $6 billion at December 31, 2003. Of these amounts, $4.8 billion and $4.3 billion were reclassified to long-term at September 30, 2004, and December 31, 2003, respectively. Settlement of these obligations was not expected to require the use of working capital in 2004, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis. The company’s practice has been to continually refinance its commercial paper, maintaining levels management believes appropriate.

At the end of the third quarter 2004, ChevronTexaco had $4.8 billion in committed credit facilities with various major banks, which permitted the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and also can be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on LIBOR or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at September 30, 2004. In addition, the company had three existing effective “shelf” registrations on file with the SEC that together would permit additional registered debt offerings up to an aggregate $3.8 billion of debt securities.

In the second quarter 2004, ChevronTexaco entered into $1 billion of interest rate fixed-to-floating swap transactions. Under the terms of the swap agreements, of which $250 million and $750 million terminate in September 2007 and February 2008, respectively, the net cash settlement will be based on the difference between fixed-rate and floating rate interest amounts.

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

The company’s future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. Further reductions from debt balances at September 30, 2004 are dependent upon many factors including management’s continuous assessment of debt as an appropriate component of the company’s overall capital structure. The company believes it has substantial borrowing capacity to meet unanticipated cash requirements, and during periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, the company

believes that it has the flexibility to increase borrowings and/or modify capital spending plans 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 1.5 at September 30, 2004, compared with 1.2 at December 31, 2003. The current ratio is adversely affected because the company’s inventories are valued on a LIFO basis. At year-end 2003 inventories were lower than replacement costs, based on average acquisition costs during the year, by nearly $2.1 billion. The company does not consider its inventory valuation methodology to affect liquidity.

Debt Ratio — total debt divided by total debt plus equity. This ratio was approximately 22 percent at September 30, 2004, compared with 26 percent at year-end 2003 and 27 percent at September 30, 2003.

Common Stock Repurchase Program. The company announced a common stock repurchase program on March 31, 2004. Acquisitions of up to $5 billion will be made from time to time at prevailing prices as permitted by securities laws and other legal requirements, and subject to market conditions and other factors. The program will occur over a period of up to three years and may be discontinued at any time. The company purchased 28,275,000 shares in the open market for $1.35 billion through September. Purchases during October increased the total shares acquired to 30,620,000 for $1.48 billion.

Pension Obligations. At the end of 2003, the company estimated that contributions to employee pension plans during 2004 would total $785 million (composed of $585 million for the U.S. plans and $200 million for the international plans). In the third quarter 2004, the company conducted additional studies to review the full year’s appropriate funding levels and funded an additional $624 million ($603 million and $21 million to the U.S. and international plans, respectively). Through September 30, 2004, a total of $1.2 billion had been contributed (all except $65 million for the U.S. plans). Contributions in the fourth quarter 2004 are estimated at $100 million.

The company will continue to review funding levels during the fourth quarter and may contribute an amount that differs from the current estimate. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors.

Capital and exploratory expenditures. Total expenditures, including the company’s share of spending by affiliates, were $5.7 billion in the first nine months of 2004, compared with $5.1 billion in the corresponding 2003 period. The company’s share of affiliate expenditures were about $1.0 billion and $700 million in the 2004 and 2003 periods, respectively. Expenditures for exploration and production projects were about $4.4 billion during 2004 — about 80 percent of the total expenditures — reflecting the company’s continued emphasis on profitably growing its upstream businesses.

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 U.S. refining and marketing operations, although presently indeterminable, could be material. ChevronTexaco has been accruing in the normal course of business any future estimated liability for potential infringement of the ‘393’ patent covered by the 1998 trial court’s ruling.

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

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

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.

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

Refer to Note 12 beginning on page 16 for discussion related to the company’s implementation of FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.”

In the second quarter 2004, ChevronTexaco entered into $1 billion interest rate fixed-to-floating swap transactions. Under the terms of the swap agreements, of which $250 million and $750 million terminate in September 2007 and February 2008, respectively, the net cash settlement will be based on the difference between fixed-rate and floating rate interest amounts.

Other than the swap transactions described above, information about market risks for the three months ended September 30, 2004, does not differ materially from that discussed under Item 7A of ChevronTexaco’s Annual Report on Form 10-K for 2003.

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 September 30, 2004, have concluded that as of September 30, 2004, 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, 2004, 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.


(1)	Includes 79,212 common shares repurchased during the three-month period ended September 30, 2004 from company employees for required personal income tax withholdings on the individual’s exercise of the stock options issued to management and employees under the company’s broad-based employee stock options, long-term incentive plans and former Texaco Inc. stock option plans. Additionally, includes 1,691,522 shares delivered or attested to in satisfaction of the exercise price by holders of certain former Texaco Inc. employee stock options exercised during the three-month period ended September 30, 2004.

(2)	All share and per share value amounts reflect the two-for-one stock split in September 2004

(3)	On March 31, 2004, the company announced a common stock repurchase program. Acquisitions of up to $5 billion will be made from time to time at prevailing prices as permitted by securities laws and other requirements, and subject to market conditions and other factors. The program will occur over a period of up to three years and may be discontinued at any time. Through September 30, 2004, $1.35 billion has been expended to repurchase 28,274,568 shares since the common stock repurchase program began.

This selected financial data from Item 6 in the company’s Annual Report on Form 10-K for 2003 has been restated to reflect the two-for-one stock split effective September 2004. Restated data is referenced in footnote 1 below.


(1)	Data restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.

(2)	The amounts in 2003 include a benefit of $0.08 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.

(3)	Chevron Corporation dividend pre-merger.

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.


	/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, 2004

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


Class		Outstanding as of September 30, 2004
Common stock, $.75 par value		2,118,612,197


		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 and Nine Months Ended September 30, 2004 and 2003		3
	Consolidated Statement of Comprehensive Income for the Three and Nine Months Ended September 30, 2004 and 2003		4
	Consolidated Balance Sheet at September 30, 2004, and December 31, 2003		5
	Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2004 and 2003		6
	Notes to Consolidated Financial Statements		7-23
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24-43
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		43
Item 4.	Controls and Procedures		43
PART II OTHER INFORMATION
Item 1.	Legal Proceedings		45
Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		45
Item 5.	Other Information		46
Item 6.	Exhibits		47
Signature			48
Exhibits: Computation of Ratio of Earnings to Fixed Charges			50
Rule 13a-14(a)/15d-14(a) Certifications			51-52
Section 1350 Certifications			53-54
EXHIBIT 12.1
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2



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

			2004		2003		2004		2003


			(Millions of dollars, except per-share amounts)
Revenues and Other Income
Sales and other operating revenues(1)			$	39,598	$	30,041	$	109,203	$	89,502
Income from equity affiliates				612		286		1,797		767
Other income.				505		148		1,566		242
Gain from exchange of Dynegy securities				—		365		—		365

	Total Revenues and Other Income			40,715		30,840		112,566		90,876

Costs and Other Deductions
Purchased crude oil and products				25,649		18,024		68,128		53,403
Operating expenses				2,554		2,225		6,950		6,002
Selling, general and administrative expenses				1,231		1,197		3,238		3,267
Exploration expenses				173		127		423		430
Depreciation, depletion and amortization				1,219		1,390		3,650		3,999
Taxes other than on income(1)				4,948		4,417		14,602		13,258
Interest and debt expense				107		115		294		363
Minority interests				23		24		63		66

	Total Costs and Other Deductions			35,904		27,519		97,348		80,788

Income From Continuing Operations Before Income Tax Expense				4,811		3,321		15,218		10,088
Income tax expense				1,875		1,360		5,643		4,448

Income From Continuing Operations				2,936		1,961		9,575		5,640
Income From Discontinued Operations				265		14		313		51

Income Before Cumulative Effect of Changes in Accounting Principles				3,201		1,975		9,888		5,691
Cumulative effect of changes in accounting principles				—		—		—		(196	)

Net Income			$	3,201	$	1,975	$	9,888	$	5,495

Per-Share of Common Stock(2):
	Income From Continuing Operations(3)
		— Basic	$	1.38	$	1.00	$	4.51	$	2.72
		— Diluted	$	1.38	$	1.00	$	4.50	$	2.72
	Income From Discontinued Operations
		— Basic	$	0.13	$	0.01	$	0.15	$	0.03
		— Diluted	$	0.13	$	0.01	$	0.15	$	0.03
	Cumulative Effect of Changes in Accounting Principles
		— Basic	$	—	$	—	$	—	$	(0.09	)
		— Diluted	$	—	$	—	$	—	$	(0.09	)
	Net Income(3)
		— Basic	$	1.51	$	1.01	$	4.66	$	2.66
		— Diluted	$	1.51	$	1.01	$	4.65	$	2.66
	Dividends		$	0.40	$	0.36	$	1.13	$	1.06
	Weighted Average Number of Shares Outstanding (000’s)(2)
		— Basic		2,113,431		2,125,436		2,120,986		2,124,947
		— Diluted		2,122,337		2,128,181		2,128,009		2,127,927

(1) Includes consumer excise taxes:			$	2,040	$	1,814	$	5,818	$	5,270


Note 4.	Assets Held for Sale and Discontinued Operations


Note 5.	Information Relating to the Statement of Cash Flows


		At September 30,		At December 31,
		2004		2003


		(Millions of dollars)
Upstream — Exploration and Production
	United States	$	11,666	$	12,501
	International		29,800		28,520

Total Exploration and Production			41,466		41,021

Downstream — Refining, Marketing and Transportation
	United States		9,725		9,354
	International		19,981		17,627

Total Refining, Marketing and Transportation			29,706		26,981

Chemicals
	United States		2,273		2,165
	International		679		662

Total Chemicals			2,952		2,827

Total Segment Assets			74,124		70,829

All Other
	United States		8,676		6,644
	International		8,220		3,997

Total All Other			16,896		10,641

Total Assets — United States			32,340		30,664
Total Assets — International			58,680		50,806

Total Assets		$	91,020	$	81,470


	Amount

	(Millions of dollars
	before tax)
Balance at January 1, 2004	$	240
Additions		37
Payments		(135	)

Balance at September 30, 2004	$	142


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


Note 9.	Summarized Financial Data — Chevron Transport Corporation


Note 17.	Cumulative Effect of Changes in Accounting Principles


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


	*U.S. Downstream — Refining, Marketing and Transportation*


	*International Downstream — Refining, Marketing and Transportation*


Item 1.	*Consolidated Financial Statements*


Note 1.	Interim Financial Statements


Note 6.	Operating Segments and Geographic Data



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

				2004			2003			2004			2003


				(Millions of dollars)
Upstream — Exploration and Production
	United States			$	3,926		$	2,952		$	12,034		$	10,232
	International				4,598			3,704			12,836			11,306

		Subtotal			8,524			6,656			24,870			21,538
	Intersegment Elimination — United States				(1,975	)		(1,302	)		(6,337	)		(4,996	)
	Intersegment Elimination — International				(2,721	)		(2,025	)		(7,482	)		(5,976	)

			Total		3,828			3,329			11,051			10,566

Downstream — Refining, Marketing and Transportation
	United States				16,268			12,590			45,084			36,756
	International				19,147			13,825			51,967			41,264

		Subtotal			35,415			26,415			97,051			78,020
	Intersegment Elimination — United States				(45	)		(55	)		(137	)		(143	)
	Intersegment Elimination — International				(35	)		(6	)		(57	)		(40	)

			Total		35,335			26,354			96,857			77,837

Chemicals
	United States				141			119			395			341
	International				217			188			644			576

		Subtotal			358			307			1,039			917
	Intersegment Elimination — United States				(52	)		(37	)		(135	)		(100	)
	Intersegment Elimination — International				(28	)		(23	)		(82	)		(62	)

			Total		278			247			822			755

All Other


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



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

			2004		2003		2004		2003

U.S. Upstream
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			499		561		522		567
	Net Natural Gas Production (MMCFPD)(3)			1,813		2,137		1,958		2,267
	Net Oil-Equivalent Production (MBOEPD)			801		917		848		945
	Sales of Natural Gas (MMCFPD)			3,927		3,683		3,942		3,893
	Sales of Natural Gas Liquids (MBPD)			184		168		181		199
	Revenue from Net Production
		Liquids ($/Bbl.)	$	36.26	$	26.09	$	32.99	$	26.83
		Natural Gas ($/MCF)	$	5.28	$	4.63	$	5.37	$	5.21
International Upstream
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			1,179		1,215		1,206		1,242
	Net Natural Gas Production (MMCFPD)(3)			1,914		1,956		2,078		2,061
	Net Oil-Equivalent Production (MBOEPD)(4)			1,642		1,671		1,694		1,693
	Sales of Natural Gas (MMCFPD)			1,908		1,815		1,900		1,987
	Sales of Natural Gas Liquids (MBPD)			92		102		101		110
	Revenue from Liftings
		Liquids ($/Bbl.)	$	37.75	$	26.36	$	33.11	$	26.66
		Natural Gas ($/MCF)	$	2.59	$	2.55	$	2.61	$	2.62
U.S. and International Upstream
	Total Net Oil-Equivalent Production including Other Produced Volumes (MBOEPD)(3)(4)			2,443		2,588		2,542		2,638
U.S. Refining, Marketing and Transportation
	Sales of Gasoline (MBPD)(5)			730		706		705		670
	Sales of Other Refined Products (MBPD)			823		805		816		765
	Refinery Input (MBPD)(6)			918		1,027		936		951
	Average Refined Product Sales Price ($/Bbl.)		$	52.47	$	40.43	$	49.54	$	40.78
International Refining, Marketing and Transportation
	Sales of Gasoline (MBPD)(5)			585		526		600		535
	Sales of Other Refined Products (MBPD)			1,296		1,219		1,272		1,240
	Affiliate Sales (MBPD)			505		498		532		515
	Refinery Input (MBPD)(6)			1,024		997		1,047		1,064
	Average Refined Product Sales Price ($/Bbl.)		$	53.91	$	43.11	$	49.93	$	42.39


(1)	Includes interest in equity affiliates.
(2)	MBPD = thousand barrels per day; MMCFPD = million cubic feet per day; Bbl. = barrel; MCF = thousand cubic feet; Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil; MBOEPD = thousand barrels of oil-equivalent (BOE) per day
(3)	Includes natural gas consumed on lease (MMCFD):
	United States	60	64	54	60
	International	280	262	295	262
(4)	Includes other international produced volumes (MBPD):
	Athabasca Oil Sands — net	31	23	29	12
	Boscan Operating Service Agreement	113	107	113	95

		144	130	142	107
(5)	Includes branded and unbranded gasoline.
(6)	2003 volumes conformed to 2004 presentation.


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


Item 2.	*Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities*


	*Disclosure Regarding Nominating Committee Functions and Communications Between Security Holders and Boards of Directors*


	*Selected Financial Data — Five-Year Financial Summary*



				Year Ended December 31,

				2003			2002		2001			2000		1999


				(Million of dollars, except per-share amounts)
Total revenues and other income				$	121,761		$	98,913	$	106,245		$	119,130	$	85,713
Net income before extraordinary items and cumulative effect of accounting change					7,426			1,132		3,931			7,727		3,247
		Extraordinary loss, net of tax			—			—		(643	)		—		—
		Cumulative effect of changes in accounting principles			(196	)		—		—			—		—

Net income				$	7,230		$	1,132	$	3,288		$	7,727	$	3,247

Per Share Amounts(1)
Basic:
	Net income before extraordinary item and cumulative effect of changes in accounting principles			$	3.57		$	0.53	$	1.85		$	3.62	$	1.51
			Extraordinary item		—			—		(0.30	)		—		—
			Cumulative effect of changes in accounting principles		(0.09	)		—		—			—		—

	Net income(2)			$	3.48		$	0.53	$	1.55		$	3.62	$	1.51
Diluted:
	Net income before extraordinary item and cumulative effect of changes in accounting principles			$	3.57		$	0.53	$	1.85		$	3.61	$	1.50
			Extraordinary item		—			—		(0.30	)		—		—
			Cumulative effect of changes in accounting principles		(0.09	)		—		—			—		—

	Net income			$	3.48		$	0.53	$	1.55		$	3.61	$	1.50
Cash dividends per share(1)(3)				$	1.43		$	1.40	$	1.33		$	1.30	$	1.24
Total assets				$	81,470		$	77,359	$	77,572		$	77,621	$	75,380
Total liabilities				$	45,175		$	45,755	$	43,614		$	44,252	$	45,589
Stockholders’ equity				$	36,295		$	31,604	$	33,958		$	33,369	$	29,791


(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


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