CHEVRONTEXACO CORP - 10-Q Quarterly Report

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

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

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

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

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

The accompanying consolidated financial statements of ChevronTexaco Corporation and its subsidiaries (the company) have not been audited by independent accountants. 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-month period ended March 31, 2004, are not necessarily indicative of future financial results.

Net income for the first quarter 2004 was $2.6 billion. Included in this amount were income of $34 million from certain assets that were classified as discontinued operations because of their pending disposition and a charge of $55 million for an adverse litigation ruling. Discontinued operations and assets held for sale are discussed in Note 3.

Net income of $1.9 billion was recorded in the first quarter 2003. Included in this amount were a charge of $196 million for the cumulative effect of changes in accounting principles, a charge of $39 million for the company’s share of losses from asset sales by an equity affiliate and income of $37 million from discontinued operations. The cumulative effect of changes in accounting principles is discussed in Note 16.

Foreign currency losses of $43 million were included in net income for the first quarter of 2004, compared with losses of $45 million in the year-ago quarter.

At March 31, 2004, and December 31, 2003, the company classified $1.2 billion and $1.1 billion, respectively, of net properties, plant and equipment for U.S. and international crude oil and natural gas producing assets as “Assets held for sale” on the Consolidated Balance Sheet. These anticipated sales, expected to occur during 2004, related to the company’s plan to dispose of certain assets in its overall portfolio that were not expected to provide sufficient long-term value.

Included in the amount at March 31, 2004, were certain assets in the company’s western Canada upstream operations that were accounted for as discontinued operations. Summarized income statement information relating to these assets is as follows:

No significant gains or losses were recorded in 2003 or the first quarter 2004 for the held-for-sale assets, including those accounted for as discontinued operations. Revenues and earnings in the first quarter 2004 and in prior periods associated with held-for-sale assets not accounted for as discontinued operations were likewise insignificant.

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

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

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

The 2004 “Net Cash Provided by Operating Activities” includes a $388 million “Decrease in other deferred charges” and a decrease of the same amount in “Other” related to balance sheet reclassifications for certain pension-related assets and liabilities, in accordance with the requirements of FAS 87, “Employers’ Accounting for Pensions.”

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

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 Financial Accounting Standards Board (FASB) Statement No. 131, “Disclosures about Segments of an Enterprise and Related Information” (FAS 131).

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. After-tax segment income (loss) from continuing operations for the three-month periods ended March 31, 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 and technology companies. Segment assets at March 31, 2004, and year-end 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-month period ended March 31, 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 quarter 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 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.


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


(1)	Includes assets held for sale of $1,054 million and $1,052 million at March 31, 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 March 31, 2004.

Taxes on income from continuing operations for the first quarter of 2004 were $1.7 billion, unchanged from last year’s first quarter. The associated effective tax rates for the 2004 and 2003 first quarters were 40 percent and 45 percent, respectively. The effective tax rate for the 2004 period was less than the rate for the comparable 2003 period primarily as a result of a lower proportion of international taxable income, which is taxed at higher rates than U.S. taxable income. Additionally, the lower effective tax rate for the 2004 first quarter was the result of a higher percentage of international downstream earnings that have historically

operated under lower tax regimes and a decrease in international upstream earnings in certain higher tax jurisdictions.

At March 31, 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:

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 are based on actual plan experience.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became law. The Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care plans that provide a benefit that is at least actuarially equivalent. The company has elected to defer recognition of the Act in the company’s measurement of the accumulated postretirement benefit obligation and net postretirement benefit costs in accordance with FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” The company continues to evaluate the impact of the legislation to its benefit plan design and accounting. Specific accounting guidance will be implemented with

issuance of FASB Staff Position No. FAS 106-b, which is currently pending, and could require the company to change previously reported information.


(1)	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.

During the first quarter 2004, the company contributed $538 million and $11 million to its U.S. and international pension plans, respectively. The company expects to contribute an additional $47 million and $189 million during the remainder of 2004 to these same plans, respectively. In the first quarter 2003, the company contributed $4 million and $16 million to its U.S. and international pension plans, respectively.

During the first quarter 2004, the company contributed $50 million to fund its other postretirement benefit plans, and additional payments of $160 million are anticipated during the remainder of 2004.

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

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

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

During 2002 and 2003, the USPTO granted two petitions for reexamination 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 has appealed the decision. Oral arguments were heard before the FTC on March 10, 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. ChevronTexaco has eliminated all but de minimis use of MTBE in gasoline it manufactures in the United States.

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 $34 million in claims submitted by Shell under these indemnities. Shell requested arbitration of this dispute which is expected to occur in the third 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 also provided indemnities pertaining to the contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the periods of ChevronTexaco’s ownership interests in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 12, 2001. Claims relating to Equilon must be asserted no later than February 2009, and claims relating to Motiva must be asserted no later than February 2012. Under the terms of the indemnities, there is no maximum limit on the amount of potential future payments. The company has not recorded any liabilities for possible claims under these indemnities. The company holds no assets as collateral and has made no payments under the indemnities.

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

Minority Interests. The company has commitments related to preferred shares of subsidiary companies, which are accounted for as minority interest. Texaco Capital LLC, a wholly owned finance subsidiary, has issued $69 million of Deferred Preferred Shares, Series C (Series C). Dividends amounting to $53 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 may result upon the occurrence of certain specific events.

refineries, crude oil fields, 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, Equatorial Guinea, Democratic Republic of Congo, South Africa, Indonesia, the Philippines, Singapore, China, Thailand, Venezuela, Argentina, Brazil, Colombia, Trinidad and Tobago and South Korea. The company’s Caspian Pipeline Consortium (CPC) affiliate operates in Russia and Kazakhstan. The company’s Tengizchevroil affiliate operates in Kazakhstan. The company’s Chevron Phillips Chemical Company LLC (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, and/or to impose additional taxes or royalties on the company’s operations.

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

Equity Redetermination. For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated 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.

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.

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

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

At issue is whether such mineral interest costs should be classified on the balance sheet as part of “Properties, plant and equipment” or as “Intangible assets.” The Emerging Issues Task Force (EITF) is addressing this in its Issue No. 03-S, “Application of FASB Statement No. 142, Goodwill and Intangible Assets, to Oil and Gas Companies.” The company will continue to classify these costs as “Properties, plant and equipment” and apportion them to expense in future periods under the company’s existing accounting policy until authoritative guidance is provided.

For ChevronTexaco, the net book value of this category of mineral interests investment at March 31, 2004 and December 31, 2003, were approximately $3.7 billion and $3.8 billion, respectively. If reclassification of these balances becomes necessary, the company’s statements of income and cash flows would not be affected. However, additional disclosures related to intangible assets would be required as prescribed under the associated accounting standards.

In 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 11 for a discussion related to FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act 2003.”

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 oil and gas producing assets and differs in several respects from previous accounting under FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.”

In the first quarter 2003, the company recorded a net after-tax charge of $200 million for the cumulative effect of the adoption of FAS 143, including the company’s share of amounts attributable to equity affiliates. The cumulative-effect adjustment also increased the following balance sheet categories: “Properties, plant and

equipment,” $2.6 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 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.

Net income for the first quarter of 2004 was $2.6 billion ($2.40 per share — diluted), compared with $1.9 billion ($1.81 per share — diluted) in the year-ago quarter. First quarter 2004 results included income of $34 million ($0.03 per share — diluted) associated with certain assets that were classified as discontinued operations because of their pending disposition. Special charges of $55 million were recorded in the current quarter relating to an adverse litigation matter.

The 2003 first quarter income included $37 million for discontinued operations. Last year’s first quarter results included net charges of $196 million ($0.18 per share — diluted) for the cumulative effect of changes in accounting principles, primarily relating to a new accounting standard for recognizing asset retirement obligations, and a special charge of $39 million for the company’s share of losses from asset sales by an international equity affiliate.

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

Earnings for upstream (exploration and production) operations in the first quarter of 2004 continued to benefit from strong crude oil and natural gas prices and were $1.951 billion — about the same as last year’s

quarter. Average prices for U.S. crude oil and natural gas liquids in the 2004 quarter increased about a dollar per barrel to more than $30 per barrel, compared with the 2003 first quarter. Internationally, the average liquids price was approximately $29 per barrel in the first quarter 2004, about the same as the year-ago quarter. The average U.S. natural gas sales price decreased 11 percent to $5.23 per thousand cubic feet, while internationally the average natural gas price of $2.67 per thousand cubic feet was marginally higher than the year-ago quarter. Partially offsetting the benefits of higher prices was lower worldwide net oil-equivalent production, including volumes produced from oil sands and production under an operating service agreement, which decreased approximately 2 percent from the first quarter of 2003. Most of the decline was associated with properties sold after last year’s first quarter. Refer to page 31 for details regarding net production volumes, including oil sands production and production under an operating service agreement.

For the downstream (refining, marketing and transportation) segment, profits of $640 million in the first quarter 2004 increased $325 million from last year’s first quarter, primarily from higher average industry margins for refined products and higher average utilization rates for the company’s worldwide refineries.

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 gains or charges.

The company’s long-term competitive position, particularly given the capital-intensive and commodity-based nature of the industry, is closely associated with the company’s ability to invest in projects that provide adequate financial returns and to manage operating expenses effectively. The company also 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 three months of 2004 and remained at slightly higher levels than the corresponding period in 2003. For the first quarter of 2004, the average spot price for WTI was over $35 per barrel, compared with about $34 per barrel in the year-ago period. These relatively high industry prices reflected increased demand from improved economies in many countries of the world and continued production curtailments by OPEC.

U.S. Benchmark prices for Henry Hub natural gas averaged nearly $5.50 per thousand cubic feet for the year 2003. In the first three months of 2004, the U.S. benchmark natural gas price averaged over $5.50 per thousand cubic feet, compared to over $6.50 per thousand cubic feet in the 2003 first quarter. Natural gas

prices were higher in the first quarter of 2003 primarily as a result of relatively lower inventory storage levels, reflecting withdrawals to meet winter demands in the United States. Natural gas prices in the United States are typically higher during the winter period, when demand for heating fuel is greatest.

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 31 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 products 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 three 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 2 percent from the year-ago period. The decrease was largely the result of lower output in the United States due to normal field declines and the result of property sales. International oil-equivalent production increased about 3 percent.

Oil-equivalent production levels in future periods are uncertain, in part because of production quotas by OPEC and the potential for local civil unrest and changing geopolitics that could cause production disruptions. Approximately 25 percent of the company’s net oil-equivalent production, including net barrels from oil sands and production under an operating service agreement, in the first quarter 2004 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 first quarter 2004 production levels in these areas were not constrained by OPEC quotas, future production could be affected by OPEC-imposed limitations.

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 property. In April 2004, an attack on a small work group assessing damage temporarily halted restoration operations in parts of the affected areas. The company intends to continue with its production-resumption plans once security can be restored and the safety of personnel can be assured. While production in 2004 was not constrained in Nigeria through early May, future OPEC actions could limit the company’s ability to produce at capacity.

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 first quarter of 2004 primarily from higher average refined product margins in most of the company’s operating areas and the absence of major refinery shut-downs. In addition, higher utilization rates throughout the company’s worldwide refinery network contributed to improved results.

Chemicals. Earnings of $74 million in the first quarter 2004 were up from the year-ago period from improved margins for lubricant additives and commodity chemicals.


	•	North America — In April, the company awarded two major engineering contracts to advance the development of the Tahiti prospect, a major discovery in the deepwater Gulf of Mexico. ChevronTexaco is the operator of the Tahiti prospect and holds a 58 percent working interest. Additionally, ChevronTexaco continued the marketing and sale of certain nonstrategic producing properties and royalty interests in the United States and western Canada as part of the company’s strategy to improve the competitive performance and operating efficiency of its exploration and production portfolio.

	•	Angola — ChevronTexaco advanced the development of the Sanha Condensate Project in offshore Angola. During the first quarter, installation teams safely completed positioning various topside modules on the three platforms of the Sanha Condensate complex. This project remains on schedule for a phased start up planned for the fourth quarter of 2004. The project, which also includes development of the Bomboco oil field, is expected to produce up to 100,000 total barrels per day of crude oil, condensate and liquefied petroleum gas by 2006.

	•	Nigeria — In April, ChevronTexaco JDZ Limited, a ChevronTexaco subsidiary, was awarded the right to conduct exploration activities in deepwater Block-1 in the Joint Development Zone (JDZ), offshore São Tomé and Príncipe and Nigeria. ChevronTexaco will be operator with a 51 percent interest in the block. Also in April, the company was awarded a 100 percent contractor interest in the deepwater Nigeria Block OPL 247 in the eastern part of the Niger Delta. Block 247 is adjacent to Block 222, which includes the company’s Usan and Ukot discoveries.

	•	United Kingdom — The company received regulatory approval to proceed with the second phase of the Alba Extreme South development. Initial production from this project is expected in late 2004. In addition, ChevronTexaco finalized the sale of its interests in the Statfjord and Galley fields and reached an agreement to sell the Orwell Field.

	•	Venezuela — ChevronTexaco was notified of an award to be issued by the Venezuelan Ministry of Energy and Mines for the Plataforma Deltana Block 3 exploration license. The block is located in an offshore area on Venezuela’s Atlantic continental shelf. The exploration rights will add to the company’s existing Block 2 license in Venezuela and Block 6d in Trinidad and Tobago, across the border with Venezuela.

	•	Global Natural Gas Projects — In Qatar, Sasol Chevron, ChevronTexaco’s 50-50 global joint venture with Sasol of South Africa, entered into a Memorandum of Understanding with Qatar Petroleum to expand the ORYX gas-to-liquids project. Qatar Petroleum and Sasol Chevron also agreed to pursue an opportunity to develop a 130,000 barrels-per-day integrated gas-to-liquids project.


	•	Worldwide Reorganization — In early 2004, the company’s downstream businesses began operating along global functional lines rather than the previous geographic alignment. This was the result of a major restructuring of the company’s global refining, marketing, and supply and trading businesses in order to improve operating efficiencies and financial performance.

	•	Singapore — The company announced plans to increase its interest in the Singapore Refining Company Pte. Ltd. (SRC) from 33 percent to 50 percent with Singapore Petroleum Company


		Limited. The acquisition of an additional interest in SRC is expected to strengthen ChevronTexaco’s existing strategic position in one of its core markets.

	•	Asset Dispositions — ChevronTexaco continued the marketing and sale of its investment in approximately 1,500 service station sites, with dispositions of its investments in more than 600 sites from the program’s inception in 2003 through the first quarter of 2004.


	•	Stock Repurchase Program — On March 31, 2004, the company announced a program to repurchase up to $5 billion of its common stock. The program began in April 2004 and the purchases will occur over a period of up to three years.

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 5 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 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 $860 million in the first quarter, down $156 million from the 2003 period, before the $350 million charge related to the adoption of a new accounting principle. First quarter 2004 earnings declined primarily due to lower natural gas prices and lower net production of liquids and natural gas. Partially offsetting these factors were higher crude oil and natural gas liquids prices and lower operating expenses compared to the year-ago quarter.

The average liquids realization for the quarter was $30.20 per barrel, compared with $29.14 in the year-ago period. The average natural gas realization for the first quarter 2004 was $5.23 per thousand cubic feet, compared with $5.85 in the 2003 quarter.

First quarter 2004 net oil-equivalent production of 875,000 barrels per day declined about 10 percent from the 2003 quarter. The decline resulted primarily from normal field declines and asset sales, the effects of which were only partially offset by increased and first-time production from various fields. The net liquids component of production was down 8 percent to 531,000 barrels per day from the year-ago period. Net natural gas production averaged 2.1 billion cubic feet per day, down about 13 percent from the year-ago quarter.

The special-item charge of $55 million in the 2004 quarter was due to an adverse litigation matter.

International exploration and production income from continuing operations increased $171 million from the year-ago quarter to $1.1 billion, due primarily to lower exploration expenses, increased sales of crude oil and natural gas liquids, and higher natural gas prices in certain countries. Partially offsetting these benefits were the effects of approximately $60 million from higher operating expenses.

The average liquids realization for the quarter was $29.26 per barrel, down about 1 percent from last year’s quarter. The average natural gas realization for the first quarter 2004 was $2.67 per thousand cubic feet, compared with $2.64 in the 2003 quarter.

Net oil-equivalent production for the first quarter 2004, including other produced volumes of 140,000 net barrels per day from oil sands and production under an operating service agreement, increased about 3 percent or 47,000 barrels per day, from the year-ago first quarter. The net liquids component increased 43,000 barrels per day to 1,365,000 barrels per day. New production in Chad and higher net production in Indonesia, Venezuela and the Athabasca oil sands project occurred during the current quarter. These effects were offset by lower net production in several countries. Planned maintenance activities in China and expansion activities in Thailand reduced net production in the first quarter 2004. Net liquids production was down in the Partitioned Neutral Zone from normal field declines and maintenance activities. Production remains shut in for security concerns in certain onshore areas of Nigeria following civil unrest in the first half of 2003. Net natural gas production of about 2.2 billion cubic feet per day in the first quarter 2004 increased by 29 million cubic feet per day over the year-ago quarter. Increased net production in Trinidad and Tobago, Kazakhstan, Venezuela and the Philippines was partially offset by lower production in Thailand, the United Kingdom and Canada.

U.S. refining, marketing and transportation earnings of $276 million improved $206 million from the 2003 quarter. The primary reasons for the improvement were an increase in average refined-product margins, higher sales volumes and lower operating expenses. Contributing to these improvements was the absence of major refinery shutdowns in 2004.

The first quarter 2004 average refined-product sales price increased nearly 2 percent to $45.10 per barrel. Sales volumes for refined products increased about 10 percent to approximately 1,461,000 barrels per day, primarily on higher sales of unbranded gasoline, diesel fuel and fuel oil. Branded gasoline sales volumes increased about 1 percent from the year-ago quarter to 545,000 barrels per day.

International refining, marketing and transportation segment income increased $119 million in the 2004 quarter. The improvement resulted primarily from higher average refined-product margins and improved earnings from equity affiliates and the company’s shipping operations, which benefited from increased freight rates.

Total refined-product sales volumes of approximately 2,370,000 barrels per day were nearly 2 percent higher in the 2004 quarter compared with last year’s quarter, primarily from higher sales of unbranded gasoline.

First quarter 2003 results included a special charge of $39 million for the company’s share of losses from asset sales by an equity affiliate.

Chemical operations earned $74 million in the first quarter of 2004, compared with $3 million in the 2003 quarter. Earnings for the company’s 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate and Oronite subsidiary improved on higher margins for commodity chemicals and lubricant additives, respectively. In the first quarter 2004, CPChem experienced high but relatively stable prices for natural gas and natural gas-based feedstocks and was able to recover these costs. In the 2003 quarter, due to the volatility in energy and feedstock costs, CPChem was not able to fully recover these costs.

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

Net segment charges before the cumulative effect of changes in accounting principles were $137 million in the first quarter of 2004, compared with net charges of $175 million in the corresponding 2003 period. The effects of lower interest expense and higher corporate income tax benefits were partially offset by lower Dynegy earnings and lower foreign exchange gains.

For further information related to the company’s investment in Dynegy, please see “Information Relating to the Company’s Investment in Dynegy” on pages 29 and 30.

Explanations are provided below of variations between the first quarters of 2004 and 2003 for certain income statement categories:

Sales and other operating revenues for the first quarter 2004 were $33 billion, up from $30.5 billion in last year’s quarter. Revenues increased mainly from higher prices for refined products worldwide.

Income from equity affiliates increased $179 million to $444 million in the first quarter 2004 primarily on improved earnings from the company’s CPChem, Tengizchevroil and downstream affiliates in the Asia-Pacific area. The first quarter 2003 included special charges of $39 million related to asset sales by an equity affiliate.

Other income of $134 million was up from $39 million in the 2003 quarter. The improvement included higher net gains from asset sales.

Purchased crude oil and products costs of $20 billion in the first quarter 2004 were up from $18 billion in the 2003 quarter. The increase for the period was primarily the result of higher prices and purchases of crude oil.

Operating, selling, general and administrative expenses of $3.2 billion in the first quarter 2004 were up from $2.9 billion in the 2003 period. The increase was primarily the result of higher transportation expenses related to tanker charters.

Exploration expenses were $84 million, compared with $154 million in the 2003 quarter. Amounts were lower for well write-offs and other exploration expenses.

Depreciation, depletion and amortization expenses of $1.2 billion were unchanged between the quarterly periods.

Taxes other than on income were $4.8 billion and $4.3 billion in the first quarter of 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 and increased duties in the U.K. and Ireland.

Interest and debt expense decreased $37 million to $93 million in the 2004 quarter, the result of lower average debt balances and a slight decrease in commercial paper interest rates between periods.

Income tax expense was $1.7 billion in both quarters. The associated effective tax rates were 40 percent and 45 percent, for the 2004 and 2003 periods for continuing operations, respectively. The lower rate in 2004 was the result of a lower proportion of international taxable income, which is taxed at higher rates than U.S. taxable income. Additionally, the lower effective tax rate for the 2004 first quarter was the result of a higher percentage of international downstream earnings that have historically operated under lower tax regimes and a decrease in international upstream earnings in certain higher tax jurisdictions.

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 March 31, 2004, the carrying value of the company’s investment in Dynegy common stock was approximately $140 million. This amount was about $420 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 $420 million difference has been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the

company’s analysis of the various factors giving rise to the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and Dynegy’s historical book values.

Investment in Dynegy Notes and Preferred Stock. The face values of the company’s investments in the Junior Notes and Series C shares are $223 million and $400 million, respectively. At March 31, 2004, the estimated fair values of the Junior Notes and Series C shares totaled $535 million, an increase of $5 million from December 31, 2003. The increase was recorded to “Investments and advances,” with an offsetting amount in “Other comprehensive income.” Future temporary changes in the estimated fair values of the new securities likewise will be reported in “Other comprehensive income.” However, if any future decline in fair value is deemed to be other than temporary, a charge against income in the period would be recorded. Interest that accrues on the notes and dividends payable on the preferred stock are recognized in income each period.

In February 2004, Dynegy announced agreement to sell its Illinois Power subsidiary to Ameren Corporation. The sale is conditioned upon, among other things, the receipt of approvals from governmental and regulatory agencies. Pending these approvals, the acquisition is expected to close in the fourth quarter of 2004. The sale of Illinois Power triggers a mandatory prepayment provision in the Dynegy Junior Notes held by the company. Under the terms of that provision, 75 percent of the net proceeds, not including any amounts used for the payment of any debt associated with Illinois Power, are to be used to retire at par, plus accrued interest, the $223 million face value notes.

Cash and cash equivalents and marketable securities totaled $6.9 billion at March 31, 2004, up from $5.3 billion at year-end 2003. Cash provided by operating activities was approximately $3.5 billion in the first three months of 2004 and was net of approximately $550 million contributed to certain of the company’s pension plans during the period. Cash provided by operating activities in the first quarter 2003 was $3.3 billion and was net of $20 million for pension plan contributions. The timing and amount of pension plan contributions are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Operating activities in the first quarter 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 three months of 2004, the company paid dividends of $775 million to common stockholders.

Debt and Capital Lease Obligations. ChevronTexaco’s total debt and capital lease obligations were $12.4 billion at March 31, 2004, down from $12.6 billion at year-end 2003.

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 March 31, 2004, down from $6.0 billion at December 31, 2003. Of these amounts, $4.3 billion was reclassified to long-term at March 31, 2004, and December 31, 2003. 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 first quarter 2004, ChevronTexaco had $4.3 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 credit requirements. No borrowings were outstanding under these facilities at March 31, 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.

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 March 31, 2004, are dependent upon 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 1.3 at March 31, 2004, compared with 1.2 at December 31, 2003. The current ratio was adversely affected at the end of 2003 and the first quarter 2004 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 the company’s liquidity.

Debt Ratio — total debt divided by total debt plus equity. This ratio was approximately 25 percent at March 31, 2004, compared with 26 percent at year-end 2003 and 32 percent at March 31, 2003.

Common Stock Repurchase Program. ChevronTexaco 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. As of April 30, 2004, the company had repurchased 1.2 million shares of common stock at a total cost of approximately $109 million.

Pension Obligations. In the first quarter of 2004 the company contributed $538 million and $11 million to the U.S. and international pension plans, respectively. During the remainder of 2004, additional funding of $47 million and $189 million for the U.S. and international pension plans, respectively, is anticipated. 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 $1.7 billion in the first three months of 2004, compared with $1.5 billion in the corresponding 2003 period. The amounts included the company’s share of affiliate expenditures of about $300 million and $150 million in the 2004 and 2003 periods, respectively. Expenditures for international exploration and production projects were about $900 million — slightly more than 50 percent of the total expenditures — reflecting the company’s continued emphasis on increasing international upstream activities. The increase from 2003 included approximately $150 million related to the company’s share of expenditures by the 50 percent-owned Tengizchevroil affiliate for the expansion of production operations for the Tengiz and Korolev fields in Kazakhstan.

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.

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.

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, 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

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.

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.

interests under Financial Accounting Standards Board (FASB) Statement No. 141, “Business Combinations” (FAS 141) and FASB Statement No. 142, “Goodwill and Intangible Assets” (FAS 142). These accounting standards became effective for the company on July 1, 2001, and January 1, 2002, respectively.

Information about market risks for the three months ended March 31, 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 March 31, 2004, have concluded that as of March 31, 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 March 31, 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.

Chevron Products Company, a division of Chevron U.S.A. Inc, has agreed to pay a $111,500 civil penalty to the Bay Area Air Quality Management District (“BAAQMD”) in settlement of 24 alleged violations of the BAAQMD’s air regulations at the company’s Richmond Refinery.

(1)

The 53,265 common shares repurchased through March 31, 2004 represent shares repurchased 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. No shares were repurchased in the first quarter under the company’s share repurchase program announced on March 31, 2004.


	(1) On April 30, 2004, ChevronTexaco furnished a copy of a press release announcing unaudited first quarter 2004 net income of $2.562 billion on a Form 8-K dated April 30, 2004.

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		CHEVRONTEXACO CORPORATION


	(Registrant)

	/s/ S. J. CROWE

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


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

		For the quarterly period ended March 31, 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 March 31, 2004
Common stock, $.75 par value		1,070,053,283


		Page
		No.

	Cautionary Statements Relevant to Forward-Looking Information for the Purpose of “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		2
PART I FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements —
	Consolidated Statement of Income for the Three Months Ended March 31, 2004 and 2003		3
	Consolidated Statement of Comprehensive Income for the Three Months Ended March 31, 2004 and 2003		4
	Consolidated Balance Sheet at March 31, 2004, and December 31, 2003		5
	Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2004 and 2003		6
	Notes to Consolidated Financial Statements		7-21
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22-38
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		38
Item 4.	Controls and Procedures		38
PART II OTHER INFORMATION
Item 1.	Legal Proceedings		39
Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		39
Item 5.	Other Information		39
Item 6.	Listing of Exhibits and Reports on Form 8-K		40
Signature			41
Exhibits: Computation of Ratio of Earnings to Fixed Charges			43
Rule 13a-14(a)/15d-14(a) Certifications			44-45
Section 1350 Certifications			46-47
Exhibit 12.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2



		Three Months Ended
		March 31,

		2004		2003(1)


		(Millions of dollars,
		except
		per-share amounts)
Revenues and Other Income
Sales and other operating revenues(2)		$	32,988	$	30,458
Income from equity affiliates			444		265
Other income			134		39

	Total Revenues and Other Income		33,566		30,762

Costs and Other Deductions
Purchased crude oil and products			19,999		18,172
Operating expenses			2,151		1,913
Selling, general and administrative expenses			1,021		1,009
Exploration expenses			84		154
Depreciation, depletion and amortization			1,192		1,232
Taxes other than on income(2)			4,766		4,330
Interest and debt expense			93		130
Minority interests			22		22

	Total Costs and Other Deductions		29,328		26,962

Income From Continuing Operations Before Income Tax Expense			4,238		3,800
Income Tax Expense			1,710		1,721

Income From Continuing Operations			2,528		2,079
Income From Discontinued Operations			34		37

Income Before Cumulative Effect of Changes in Accounting Principles			2,562		2,116
Cumulative effect of changes in accounting principles, net of tax			—		(196	)

Net Income		$	2,562	$	1,920


Per Share of Common Stock:
	Income From Continuing Operations
		— Basic	$	2.38	$	1.96
		— Diluted	$	2.37	$	1.96
	Income From Discontinued Operations
		— Basic	$	0.03	$	0.03
		— Diluted	$	0.03	$	0.03
	Cumulative Effect of Changes in Accounting Principles
		— Basic		—	$	(0.18	)
		— Diluted		—	$	(0.18	)
	Net Income
		— Basic	$	2.41	$	1.81
		— Diluted	$	2.40	$	1.81
	Dividends		$	0.73	$	0.70
	Weighted Average Number of Shares Outstanding (000s)
		— Basic		1,063,409		1,062,017
		— Diluted		1,066,180		1,063,600



(1) 2003 conformed to the 2004 presentation for discontinued operations.
(2) Includes consumer excise taxes:	$	1,857	$	1,691


				At March 31,			At December 31,
				2004			2003


				(Millions of dollars, except
				per-share amounts)
ASSETS
Cash and cash equivalents				$	5,858		$	4,266
Marketable securities					1,023			1,001
Accounts and notes receivable					11,224			9,722
Inventories:
	Crude oil and petroleum products				2,292			2,003
	Chemicals				168			173
	Materials, supplies and other				442			472

		Total inventories			2,902			2,648
Prepaid expenses and other current assets					1,838			1,789

		Total Current Assets			22,845			19,426
Long-term receivables, net					1,493			1,493
Investments and advances					12,707			12,319
Properties, plant and equipment, at cost					99,603			100,556
Less: accumulated depreciation, depletion and amortization					55,370			56,018

		Properties, plant and equipment, net			44,233			44,538
Deferred charges and other assets					2,617			2,594
Assets held for sale					1,212			1,100

			Total Assets	$	85,107		$	81,470

LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt				$	1,525		$	1,703
Accounts payable					9,691			8,675
Accrued liabilities					3,007			3,172
Federal and other taxes on income					2,388			1,392
Other taxes payable					1,236			1,169

		Total Current Liabilities			17,847			16,111
Long-term debt					10,635			10,651
Capital lease obligations					245			243
Deferred credits and other noncurrent obligations					7,858			7,758
Noncurrent deferred income taxes					6,720			6,417
Reserves for employee benefit plans					3,339			3,727
Minority interests					297			268

		Total Liabilities			46,941			45,175

Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued)					—			—
Common stock (authorized 4,000,000,000 shares, $.75 par value, 1,137,016,007 and 1,137,021,057 shares issued at March 31, 2004 and December 31, 2003, respectively)					853			853
Capital in excess of par value					4,862			4,855
Retained earnings					37,105			35,315
Accumulated other comprehensive loss					(799	)		(809	)
Deferred compensation and benefit plan trust					(576	)		(602	)
Treasury stock, at cost (66,962,724 and 67,873,337 shares at March 31, 2004 and December 31, 2003, respectively)					(3,279	)		(3,317	)

		Total Stockholders’ Equity			38,166			36,295

			Total Liabilities and Stockholders’ Equity	$	85,107		$	81,470


Note 4.	Information Relating to the Statement of Cash Flows


	Amount

	(Millions of dollars
	before tax)
Balance at January 1, 2004	$	240
Additions		26
Payments		(85	)

Balance at March 31, 2004	$	181


Note 7.	Summarized Financial Data — Chevron U.S.A. Inc.


Note 8.	Summarized Financial Data — Chevron Transport Corporation



			Three Months
			Ended
			March 31,

			2004			2003


			(Millions of
			dollars)
Pension Benefits
United States
	Service cost		$	42		$	33
	Interest cost			82			84
	Expected return on plan assets			(87	)		(56	)
	Amortization of prior-service costs			11			11
	Recognized actuarial losses			28			29
	Settlement losses			20			35

		Total United States		96			136

International
	Service cost			17			11
	Interest cost			43			33
	Expected return on plan assets			(41	)		(24	)
	Amortization of transitional assets			—			(1	)
	Amortization of prior-service costs			4			3
	Recognized actuarial losses			13			9

		Total International		36			31

Net Periodic Pension Benefit Costs			$	132		$	167

Other Benefits(1)
	Service cost		$	8		$	7
	Interest cost			46			47
	Amortization of prior-service costs			(1	)		(1	)
	Recognized actuarial losses			7			3

Net Periodic Other Benefit Cost			$	60		$	56


Note 16.	Cumulative Effect of Changes in Accounting Principles


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


Item 1.	*Consolidated Financial Statements*



				Three Months Ended
				March 31,

				2004			2003


				(Millions of dollars)
Upstream — Exploration and Production
	United States			$	4,322		$	3,710
	International				3,604			3,568

		Sub-total			7,926			7,278
	Intersegment Elimination — United States				(2,452	)		(1,779	)
	Intersegment Elimination — International				(1,859	)		(1,750	)

			Total		3,615			3,749

Downstream — Refining, Marketing and Transportation
	United States				13,425			12,150
	International				15,550			14,229

		Sub-total			28,975			26,379
	Intersegment Elimination — United States				(29	)		(40	)
	Intersegment Elimination — International				—			(5	)

			Total		28,946			26,334

Chemicals
	United States				124			108
	International				216			199

		Sub-total			340			307
	Intersegment Elimination — United States				(39	)		(31	)
	Intersegment Elimination — International				(26	)		(20	)

			Total		275			256

All Other


Note 9.	Income Taxes


Note 10.	Stock Options


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


(1)	Includes equity in 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	51	39
	International	282	269
(4)	2003 volumes conformed to 2004 presentation.


(5)	Other produced volumes (MBPD) include:
	Athabasca oil sands — net	27	1
	Boscan Operating Service Agreement	113	75
(6)	Includes branded and unbranded gasoline.


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*


(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