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 x 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; future developments in the energy-trading business sector and their effects on the operations of the company and its Dynegy affiliate; inability of the company’s joint-venture partners to fund their share of operations and development activities; potential failure to achieve expected production from existing and future oil and gas development projects; potential delays in the development, construction or start-up of planned projects; the successful integration of the former Chevron, Texaco and Caltex businesses; potential disruption or interruption of the company’s production or manufacturing facilities due to accidents or political events; 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); and potential liability resulting from pending or future litigation. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

The accompanying consolidated financial statements of ChevronTexaco Corporation and its subsidiaries (the company) have not been audited by independent accountants, except for the balance sheet at December 31, 2001. 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 special items and merger-related expenses described in Note 2, including the write-down of the company’s investment in Dynegy Inc. (Dynegy) discussed in detail in Note 3.

On October 9, 2001, Texaco Inc. (Texaco) became a wholly owned subsidiary of Chevron Corporation (Chevron) pursuant to a merger transaction, and Chevron changed its name to ChevronTexaco Corporation. The combination was accounted for as a pooling of interests. The accompanying consolidated financial statements give retroactive effect to the merger, with all periods presented as if Chevron and Texaco had always been combined.

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 2001 Annual Report on Form 10-K.

The results for the three- and six-month periods ended June 30, 2002, are not necessarily indicative of future financial results.

Net income for the second quarter of 2002 included special charges of $753 million and $73 million for merger-related expenses. The special charges included $531 million for a write-down of ChevronTexaco’s investment in its Dynegy affiliate, which is discussed in Note 3; $100 million for the company’s share of Dynegy’s own write-downs and other adjustments; and $122 million for environmental remediation costs and the settlement of a litigation issue. The 2001 second quarter included $36 million for merger-related expenses.

Net income for the first six months of 2002 included special charges of $827 million and merger-related expenses of $205 million. In addition to the second quarter 2002 special items, the six-month period included a special charge of $74 million for the company’s share of a write-down by Dynegy of investments in its telecommunications businesses. Net income for the first six months of 2001 included merger-related expenses of $57 million.

Foreign currency losses were $141 million and $20 million in the second quarters 2002 and 2001, respectively. For the six-month periods, losses were $10 million in 2002, compared with gains of $67 million in 2001.

ChevronTexaco’s Dynegy Inc. equity affiliate is an energy merchant with physical assets and marketing, logistics and risk-management capabilities for products, including natural gas, natural gas liquids and electricity. ChevronTexaco owns approximately 26 percent of Dynegy’s common stock and also holds $1.5 billion aggregate principal amount of Dynegy preferred stock. Dynegy is obligated to redeem all the preferred stock for an aggregate $1.5 billion in cash in November 2003, except to the extent ChevronTexaco chooses to convert preferred shares into Dynegy common stock at a conversion price of $31.64 per share. ChevronTexaco accounts for its investment in Dynegy as part of “All Other” for financial reporting purposes.

Under a long-term contract, Dynegy purchases most natural gas produced by ChevronTexaco in the United States. ChevronTexaco is a secured creditor with respect to amounts owed by Dynegy for these purchases, which are included as revenues in results of operations for ChevronTexaco’s U.S. exploration and production (upstream) reporting segment.

collateralization of its business operations and depressed levels of commercial activity. Dynegy’s debt ratings have been downgraded below investment grade level, and it is the subject of regulatory investigations and is the defendant in a number of lawsuits seeking large amounts of damages. Additionally, at the request of Dynegy, its independent accountants are currently conducting a re-audit of Dynegy’s 1999-2001 financial statements in anticipation of their restatement and thereafter the independent accountants will perform interim reviews of Dynegy’s 2002 quarterly financial statements. Dynegy’s ability to meet its obligations in the ordinary course may depend largely on its ability to execute in a timely fashion an announced $2 billion capital program, including the pending sale of Northern Natural Gas Company.

ChevronTexaco’s net income for the second quarter of 2002 included a charge of $531 million for a partial write-down of the investment in Dynegy common and preferred stock to its estimated fair value at June 30, 2002. In addition, second quarter net income included a charge of $100 million for ChevronTexaco’s share of Dynegy’s own write-downs and other adjustments. See also Note. 2 for a discussion of special items included in net income.

The write-down of the company’s investment in Dynegy was required under applicable accounting rules because the decline in the fair value of the investment below its carrying value was determined to be other than temporary. Further deterioration in the securities’ fair value subsequent to June 30, 2002, was not reflected in the second quarter charge. Following the write-down, the remaining book value of the company’s investment in Dynegy at June 30, 2002, was $1.981 billion – composed of $1.283 billion for the preferred stock and $698 million for the common stock. An additional charge to third quarter earnings would be required to the extent the fair value of the Dynegy securities at September 30, 2002, is below the carrying value, and the decline in value is deemed to be other than temporary.

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

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

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

“Net purchases of other short-term investments,” of $666 million in 2001 were in a variety of short-term money market instruments with maturities similar to the company’s commercial paper portfolio. There were no investments under this program in 2002.

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


*	Deferred payment related to 1993 acquisition of an interest in the Tengizchevroil joint venture.

The Consolidated Statement of Cash Flows excludes two separate non-cash transactions affecting the balance sheet that were for the company’s Employee Stock Ownership Plan (ESOP) repayments of $100 million each of matured debt guaranteed by ChevronTexaco Corporation in January 2002 and 2001. These payments were recorded by the company as reductions to “Short-term debt” and “Deferred Compensation.”

ChevronTexaco separately manages its exploration and production; refining, marketing and transportation; and chemicals businesses. “All Other” activities include corporate administrative costs, worldwide cash management and debt financing activities, the company’s investment in Dynegy, coal mining operations, power and gasification operations, technology investments, insurance operations and real estate activities. The company’s primary country of operation is the United States of America, its country of domicile. The remainder of the company’s operations is reported as International (outside the United States).

The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating

segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs and merger effects remain at the corporate level. After-tax segment income (loss) for the three- and six-month periods ended June 30, 2002 and 2001, is presented in the following table:

Segment assets do not include intercompany investments or intercompany receivables. “All Other” assets consist primarily of worldwide cash and marketable securities, real estate, information systems, the investment in Dynegy Inc., coal mining operations, power and gasification operations and technology investments. At

December 31, 2001, this category also included $2.2 billion for merger-related assets held for sale. Segment assets at June 30, 2002, and year-end 2001 follow:

Operating segment sales and other operating revenues, including internal transfers, for the three- and six-month periods ended June 30, 2002 and 2001, are presented in the following table. Sales from the transfer of products between segments are at prices that approximate market.

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

The company expects to incur approximately $2 billion of one-time before-tax expenses in connection with the merger of Chevron and Texaco. Major expenses include employee severance payments; incremental pension and medical plan benefit costs associated with workforce reductions; legal, accounting, SEC filing and investment banker fees; employee and office relocations; and costs for the elimination of redundant facilities and operations.

In 2001, before-tax merger-related expenses were $1.563 billion ($1.136 billion after tax). In the three- and six-month periods ended June 30, 2002, such expenses were $119 million ($73 million after tax) and $302 million ($205 million after tax), respectively. The cumulative total of $1.865 billion ($1.341 billion after tax) included accruals of $891 million and $13 million in 2001 and the first six months 2002, respectively, for severance-related benefits for approximately 4,500 employees and other merger-related expenses that will not benefit future operations.

Activity for this merger-related accrual balance is summarized in the table below:

The ending accrual balance is expected to be extinguished within one year, except for $56 million classified as long-term, which is associated with elections by certain employees to defer severance payments until 2004. Approximately 3,500 of the 4,500 employees had terminated by June 30, 2002. Substantially all of the remaining terminations are expected to occur by the end of this year.

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 and assets related to the exploration and production of crude oil, natural gas and natural gas liquids and also those associated with refining, marketing, supply and distribution of products derived from petroleum, other than natural gas liquids, excluding most of the pipeline operations of ChevronTexaco. CUSA also holds divisions overseeing or operating global businesses such as aviation fuel, lubricants, shipping and trading, and divisions providing administrative, technical, etc. services to affiliated companies. CUSA also holds ChevronTexaco’s investment in the Chevron Phillips Chemical Company joint venture, which is accounted for using the equity method, and Dynegy Inc.

During the second quarter of 2002, ChevronTexaco implemented a legal reorganization in which certain ChevronTexaco subsidiaries transferred assets to or under CUSA and other ChevronTexaco companies were merged with and into CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the table below gives retroactive effect to the reorganization in a manner similar to a pooling of interests, with all periods presented as if the companies had always been combined and the reorganization had occurred on January 1, 2001. However, the financial information included below may not reflect the financial

position and operating results in the future or the historical results in the periods presented had the reorganization actually occurred on January 1, 2001.

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 June 30, 2002.

Taxes on income for the second quarter and first half 2002 were $876 million and $1.466 billion, respectively, compared with $1.911 billion and $3.668 billion for the comparable periods in 2001. The effective tax rates for the second quarter 2002 and 2001 were 68 percent and 48 percent, respectively. For the year-to-date periods, the effective tax rates were 56 percent and 45 percent, respectively. The increase in the effective tax rate for both 2002 periods was primarily the result of a higher proportion of international before-tax income, generally taxed at higher rates, whereas the U.S. operations generated before-tax losses. In the second quarter 2002, a significant portion of the write-down of the company’s investment in Dynegy did not generate U.S. tax benefits.

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 reformulated gasoline, which ChevronTexaco sells 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 in infringement 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 from August 1, 1996, to September 30, 2000. Additionally, the U.S. Patent and Trademark Office (USPTO) granted a motion by the refiners to re-examine the validity of Unocal’s patent. The District Court judge requested further briefing and advised that she would not enter final judgement orders in this case until the USPTO had completed its reexamination of the ‘393’ patent. During 2002 the USPTO rejected the validity of the ‘393’ patent and another Unocal patent, the ‘126’ patent, which could affect a larger share of U.S. gasoline production. Separately, the U.S. Federal Trade Commission has also announced that it is investigating whether Unocal’s conduct in this matter was unfair competition, which may make Unocal’s patent unenforceable.

Unocal has obtained additional patents that could affect a larger share of U.S. gasoline production. ChevronTexaco believes these additional patents are invalid, unenforceable and/or not infringed. The company’s financial exposure in the event of unfavorable conclusions to the patent litigation and regulatory reviews may include royalties, plus interest, for production of gasoline that is proved to have infringed the patents. The competitive and financial effects on the company’s refining and marketing operations, while presently indeterminable, could be material. ChevronTexaco – as well as Chevron and Texaco separately pre-merger – 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 $28 million for the original court ruling, including interest and fees.

certain oxygenated gasolines. These actions may require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. In July 2002, ChevronTexaco and Exxon Mobil Corp. (ExxonMobil) reached a settlement of an MTBE-related litigation matter with the City of Santa Monica, California. Under the terms of the settlement, ChevronTexaco and ExxonMobil guaranteed to fund the cost of building and operating a water treatment facility to remove MTBE and other contaminants from certain water wells and to pay a cash settlement to cover costs of alleged contamination. The City of Santa Monica agreed to release ChevronTexaco and ExxonMobil from a lawsuit filed in 2000 against a group of oil refiners, suppliers, and owners and operators of pipelines and other facilities for allegedly contaminating water wells with MTBE. The settlement also states that ChevronTexaco and ExxonMobil may be repaid a portion of the construction and operating costs if the City of Santa Monica fully recovers funds from the other companies named in the suit. ChevronTexaco has worked to reduce the use of MTBE in gasoline it manufactures in the United States. The State of California has directed that MTBE be phased out of the manufacturing process by the end of 2003, and the company intends to comply with this mandate.

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

Settlement of open tax years, as well as tax issues in other countries where the company conducts its businesses, is not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provision has been made for income and franchise taxes for all years under examination or subject to future examination.

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.

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

ChevronTexaco provided certain indemnities of contingent liabilities of Equilon Enterprises LLC (Equilon) and Motiva Enterprises LLC (Motiva) to Shell Oil Company and Saudi Refining, Inc. as part of the February 2002 sale of the company’s interests in those investments. Generally, the indemnities provided are limited to contingent liabilities that may become actual liabilities within 18 months of the sale and are reduced by any reserves that were established prior to the sale. Excluding environmental liabilities, the company’s financial exposure related to those indemnities is limited to $300 million. Additionally, the company has provided indemnities for certain environmental liabilities arising out of conditions that existed prior to the formation of Equilon and Motiva and during the periods of ChevronTexaco’s ownership interest in those entities as well as for customary representations and warranties within the agreements.

may exist for various sites, including but not limited to: Superfund sites and refineries, oil fields, service stations, terminals, and land development areas, whether operating, closed or sold. The amount of such future cost is indeterminable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. While the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of 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.

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 also suspends the costs of exploratory wells pending a final determination of the commercial potential of the related oil and gas fields. The ultimate disposition of these well costs is dependent on the results of future drilling activity and/or development decisions. If the company decides not to continue development, the costs of these wells are expensed. The company and its affiliates also routinely assess 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 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, including Dynegy, may be affected by their business activities involving the use of derivative instruments.

The company’s operations, particularly exploration and production, can be affected by other changing economic, regulatory and political environments in the various countries in which it operates, including the United States. The Organization of Petroleum Exporting Countries (OPEC) has at times made efforts to support crude oil prices by limiting production, which can affect production at the company’s facilities, and those of its partners, in OPEC member countries. 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.

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

Hills in California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. ChevronTexaco currently estimates its maximum possible net before-tax liability at less than $400 million. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at more than $200 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

Recent interpretations of Financial Accounting Standards Board (FASB) Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS 133), as amended by FAS 138, “Accounting for Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”, by the FASB Derivatives Implementation Group prescribe mark-to-market accounting for certain natural gas sales contracts. Some of these interpretations became effective January 1, 2002. Adoption at that time did not result in a material effect to net income. Other interpretations became effective April 1, 2002, and apply to certain power sales agreements of the company’s affiliates. Upon adoption of these interpretations, certain power sales agreements of the company’s affiliates were recorded as cash flow hedges. An after-tax gain of approximately $40 million was included in other comprehensive income in the second quarter reflecting the company’s share of the change in the fair value of the cash flow hedges. The effect of these cash flow hedges upon net income in the second quarter was not significant.

In June 2001, the FASB issued Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 is effective for fiscal years beginning after June 15, 2002. FAS 143 differs in several significant respects from current accounting for asset retirement obligations under FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Adoption of FAS 143 will affect future accounting and reporting of the assets, liabilities and expenses related to these obligations. The magnitude of the effect has not yet been determined.

Effective July 15, 2002, Consensus 02-3 of the FASB Emerging Issues Task Force (EITF) requires companies involved in energy trading and risk management activities to present the gains and losses stemming from those activities on a net basis in the income statement. The company is currently evaluating these reclassification requirements, which will have no impact on net income.

In July, the FASB issued Statement No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. The statement replaces EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” FAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.

Net income for the second quarter 2002 was $407 million ($0.39 per share – diluted), compared with net income of $2.108 billion ($1.99 per share – diluted) for the 2001 second quarter. Net income for this year’s second quarter included special charges of $753 million and $73 million for merger-related expenses. The special charges included $531 million for the write-down of the company’s investment in its Dynegy Inc. (Dynegy) affiliate; $100 million for the company’s share of Dynegy’s own write-downs and other adjustments; and $122 million for environmental remediation costs and the settlement of a litigation issue. The second quarter 2001 included $36 million for merger-related expenses. Excluding special items and merger effects in both quarters, operating earnings were $1.233 billion ($1.16 per share – diluted), down over 40 percent from last year’s second quarter.

Net income for the first six months of 2002 was $1.132 billion ($1.07 per share – diluted), compared with $4.541 billion ($4.28 per share – diluted) recorded in the first half of 2001. Special items reduced earnings $827 million in 2002 and merger-related expenses were $205 million. The 2001 six months included $57 million for merger-related expenses. Excluding special items and merger effects in both six-month periods, operating earnings of $2.164 billion in 2002 were down more than 50 percent from last year’s results.

Earnings in both 2002 periods were adversely affected by lower prices for crude oil and natural gas and lower margins for refined products than in last year’s periods. The lower prices affected the company’s U.S. businesses the most. U.S. exploration and production (upstream) segment earnings fell by 38 percent and 61 percent for

the second quarter and six-month periods, respectively. The average U.S. natural gas realization for the quarter dropped nearly 40 percent from the year-ago period to $3.04 per thousand cubic feet. The average U.S. crude oil and natural gas liquids realization was about one dollar per barrel lower in the 2002 quarter at $21.75 per barrel. For the six-month period, the average U.S. natural gas realization was down 57 percent to $2.66 per thousand cubic feet, while the average U.S. crude oil and natural gas liquids realization was nearly 18 percent lower at $19.35 per barrel.

U.S. refining, marketing and transportation (downstream) earnings reflected significantly lower refining and marketing margins for both the quarter and six-month periods. Although improved from lower levels early this year, refined product margins remained weak. The second quarter and six-month 2001 periods also included $208 million and $256 million, respectively, of earnings from assets that were sold under mandate of the U.S. Federal Trade Commission (FTC) as a condition of the merger. International downstream results declined due to the adverse effects of foreign currency fluctuations and lower freight rates for the international shipping organizations. Margins declined in the Asia-Pacific and European areas of operations but improved slightly in Latin America.

Under mandate of the FTC, the company sold its interests in Equilon and Motiva – joint ventures engaged in U.S. downstream businesses – in February, resulting in cash proceeds of $2.2 billion, including dividends due. Other mandated asset dispositions were completed in the second quarter. Net income and cash proceeds from these other sales were not material.

Company employees worldwide are implementing initiatives to capture savings from merger synergies. At the beginning of second quarter 2002, the company had achieved a run rate of $1.2 billion before tax in annual synergy savings and expects to achieve its interim target run rate of $1.8 billion before tax in annual synergy savings by October 2002, six months ahead of the original schedule. The company announced a new target of $2.2 billion of annual synergy savings to be achieved by April 2003. Some examples of the merger integration initiatives to-date are as follows:


•	Exploration – High-grading investment opportunities in the combined-company portfolio; sharing knowledge of drilling prospects by staffs of the combining companies. Combined company exploration expenses for six months 2002 were about 46 percent lower than in the same period last year pre-merger.

•	Production – Leveraging operating efficiencies in common areas operated separately by Chevron and Texaco prior to the merger; high-grading development spending to increase production volumes. Progress has also been made in reducing operating expenses in areas of overlap for upstream producing operations, including reducing the consumption of steam used in the company’s heavy oil operations in California’s San Joaquin Valley.

•	Refining – Collaborating across the worldwide refinery network to adopt best practices in process technology.

•	Shipping – Improving the use of company and chartered tankers as more opportunities are provided to optimize ship utilization.

•	Procurement – Leveraging the company’s size and purchasing power to reduce both capital costs and operating expenses. For example, in the company’s marketing operations, benefits have been achieved to reduce the cost of advertising, convenience store operations and the product distribution network.

•	Corporate and Other – Consolidating offices, computer systems and telecommunications networks. The company has also redeemed certain higher-cost debt and reduced combined interest costs.

The company expects to incur approximately $2 billion of one-time before-tax expenses through 2002 in connection with the Chevron and Texaco merger transaction. Major expenses include employee severance payments; incremental pension and medical plan benefit costs associated with workforce reductions; legal, accounting, SEC filing and investment banker fees; employee and office relocations; and costs for the elimination of redundant facilities and operations.

Activity for this merger-related accrual balance is summarized in the table below:


•	U.S. Exploration and Production – In July, ChevronTexaco and its partners reached agreement to relinquish interests in the Destin Dome 56 Unit leases, offshore Florida. ChevronTexaco will receive approximately $46 million from the federal government as compensation for the investment made to date in the development. It is expected that payment will be received later in the third quarter and that the effect of the settlement on net income will not be material.

•	Norway – ChevronTexaco was awarded interests in two licenses on the Norwegian Continental Shelf, adding 115 square miles for oil and gas exploration. The licenses are located offshore about 90 to 150 miles, in water depths of 1,900 to 3,000 feet.

•	Nigeria – The company announced a second oil discovery on the non-operated deepwater Nigerian Block OPL 222. The discovery – Usan-1 – is approximately 60 miles offshore in a water depth of over 2,000 feet. Ukot-1, the first oil discovery on the block, was drilled and tested in 1998. Following the drilling of Usan-1, a comprehensive evaluation of the discovery and block commercial potential will be undertaken.

•	Angola – The eighth significant discovery – Gabela – was made in Angola’s ChevronTexaco-operated deepwater Block 14. This latest discovery will be followed by geological and engineering studies to assess its reserve potential.

•	China – ChevronTexaco and its partners confirmed an oil discovery in the Liaodong Bay 02/31 Block in Bohai Bay, China. The well, drilled in approximately 60 feet of water, encountered multiple oil zones that tested at a combined rate of 4,600 barrels per day.

•	Qatar – Chevron Phillips Chemical Company LLC, a 50 percent-owned affiliate, signed an agreement for a 49 percent interest in a $1.1 billion project to produce high density polyethylene and normal alpha olefins in Qatar.

ChevronTexaco’s exploration and production earnings are affected significantly by fluctuations in industry price levels for crude oil and natural gas. Average U.S. natural gas and crude oil prices in the first half of 2002 were significantly lower than in last year’s first half. Henry Hub spot natural gas prices declined about 47 percent from $5.54 to $2.94 per thousand cubic feet. The average spot price for West Texas Intermediate (WTI), a benchmark crude oil, was $24.02 per barrel, compared with $28.33 in last year’s first half. In early August, the spot WTI price was about $27.00 per barrel, and the Henry Hub spot natural gas price was $3.00 per thousand cubic feet.

The Organization of Petroleum Exporting Countries (OPEC) continues its effort to support crude oil prices by limiting production. OPEC curtailments restrained ChevronTexaco’s net production by approximately 40,000 barrels per day in the first half of 2002, versus having no effect in the corresponding 2001 period. In addition, production under certain operating service agreements, which is not included in the company’s net working interest production, was also curtailed 20,000 barrels per day in this year’s first half, compared with approximately 7,000 barrels per day in the year-ago period. The long-term effect on industry prices due to OPEC production quotas remains uncertain.

In addition to OPEC production quotas, the company’s operations are periodically affected by operating incidents, civil unrest, political uncertainty and economic conditions. In July 2002, international production of crude oil and natural gas was adversely affected by operating incidents in Nigeria, Angola and the United Kingdom. The effect of these incidents on the company’s average third quarter oil-equivalent production is expected to be about 35,000 barrels per day. Substantially all of the shut-in production had resumed by early August.

In July, the United Kingdom (U.K.) enacted changes to the U.K. North Sea tax regulations, under which a supplementary charge will effectively increase the U.K. corporation tax rate from 30 percent to 40 percent. The changes are effective from April 17, 2002. The company will record a one-time charge of approximately $100 million against net income in the third quarter to adjust historical deferred tax balances. On an annual basis, the company estimates incremental income tax expense of approximately $50 million as a result of the higher tax rates – based upon current forecasts of crude oil and natural gas prices, capital expenditures and production levels. The impact of the tax change on cash flow for the remainder of 2002 and for the 2003-2004 period is anticipated to be largely neutral, as accelerated capital allowances will essentially offset effects of the higher tax rate.

Downstream operating earnings are closely tied to refining and marketing margins, which can vary among the geographic areas in which the company operates. Results from the company’s downstream business, particularly in the United States, were negatively affected during the first half of 2002 by industry margins that early in the year had been at their lowest levels since the mid-1990s. Product margins in the United States trended upward in the second quarter of 2002. However, competitive markets and weak demand – reflective of slowed world economies – may hamper near-term improvement in profits for this sector.

Chemicals margins remained weak because of a protracted industry over-supply condition and are not expected to improve significantly in the near-term.

Under a long-term contract, Dynegy purchases most of the natural gas produced by ChevronTexaco in the United States. ChevronTexaco is a secured creditor with respect to amounts owed by Dynegy for these

Dynegy is experiencing a marked reduction in available liquidity resulting from a combination of lower than previously anticipated cash flow from operations, significantly impaired access to sources of capital, increased collateralization of its business operations and depressed levels of commercial activity. Dynegy’s debt ratings have been downgraded below investment grade level, and it is the subject of regulatory investigations and is the defendant in a number of lawsuits seeking large amounts of damages. Additionally, at the request of Dynegy, its independent accountants are currently conducting a re-audit of Dynegy’s 1999-2001 financial statements in anticipation of their restatement and thereafter the independent accountants will perform interim reviews of Dynegy’s 2002 quarterly financial statements. Dynegy’s ability to meet its obligations in the ordinary course may depend largely on its ability to execute in a timely fashion an announced $2 billion capital program, including the pending sale of Northern Natural Gas Company.

ChevronTexaco’s net income for the second quarter of 2002 included a charge of $531 million for a partial write-down of the investment in Dynegy common and preferred stock to its estimated fair value at June 30, 2002. In addition, second quarter net income included a charge of $100 million for ChevronTexaco’s share of Dynegy’s own write-downs and other adjustments. These charges to ChevronTexaco net income have been classified as special items apart from operating earnings in this management’s discussion.

Total revenues and other income for the second quarter 2002 were $25.3 billion, down from $29.7 billion in last year’s second quarter. For the first six months of 2002, total revenues and other income were $46.5 billion, down from $59.1 billion in the corresponding 2001 period. Revenues and other income from worldwide upstream operations decreased about 42 percent in the 2002 six months, primarily on lower prices for crude oil and natural gas, worldwide. Additionally sales volumes of natural gas in the United States were down in 2002. Downstream revenues and other income were also down about 8 percent – the result of lower refined products prices.

Operating, selling, general and administrative expenses, excluding special items, in the second quarter of 2002 were $2.663 billion, down slightly from $2.730 billion in last year’s second quarter. For the six-month period, such expenses, excluding special items, were $5.278 billion, compared with $5.507 billion in last year’s first half, mainly due to lower fuel costs earlier in the year and the benefits of merger synergies.

Exploration expenses in the second quarter of 2002 were $135 million, down from $249 million in last year’s second quarter. For the six-month period, exploration expenses were $220 million, compared to $411 million in 2001. Both 2002 periods benefited from reduced amounts for well write-offs and declines in other exploration expenses.

Depreciation, depletion and amortization (DD&A) expense was $1.241 billion in the second quarter of 2002, compared with $1.168 billion in the 2001 quarter. For the six-month periods, DD&A expense of $2.446 billion was $121 million higher than in the first half of 2001.

2002 periods was primarily the result of a higher proportion of international before-tax income, generally taxed at higher rates, whereas the U.S. operations generated before-tax losses. In the second quarter 2002, a significant portion of the write-down of the company’s investment in Dynegy did not generate U.S. tax benefits.

Foreign currency losses included in second quarter 2002 net income were $141 million compared with $20 million in the year-ago period. In 2002, fluctuations of the U.S. dollar against the currencies of most other countries in which the company has significant operations resulted in losses, with the notable exception of the Argentine peso, which was permitted to float against the dollar earlier in the year. For the six-month periods, foreign currency losses were $10 million in 2002, compared with gains of $67 million in 2001.


	¹ Includes equity in affiliates.

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

	³ Decrease between periods reflects reductions in company’s trading activity.

	⁴ Represents total field production under the Boscan operating service agreement in Venezuela.

	⁵ Excludes Equilon and Motiva.

	⁶ Includes branded and unbranded gasoline.

U.S. exploration and production operating earnings of $548 million in the 2002 quarter declined mainly due to significantly lower natural gas realizations, lower liquids realizations and a decline in oil-equivalent production. The average natural gas realization for the quarter was $3.04 per thousand cubic feet, compared with $4.80 in the year-ago period. The average natural gas realization for the first half of 2002 was $2.66 per thousand cubic feet, less than half the $6.18 obtained in the year-ago period. The average liquids realization was down about 5 percent to $21.75 per barrel in the second quarter and down nearly 18 percent to $19.35 in the first half of the year. Partially offsetting these unfavorable earnings impacts were lower operating and exploration expenses in the 2002 quarter and six months.

Net oil-equivalent production declined 3 percent from last year’s second quarter and 4 percent for the six months. The net liquids production component was up 2 percent to 627,000 barrels per day in the quarter and 623,000 barrels per day year to date. Net natural gas production averaged 2.504 billion cubic feet per day in the second quarter, down 10 percent from the 2001 period. Six-month natural gas production was 2.506 billion cubic feet per day, compared with 2.835 billion cubic feet per day in the year ago period. Drilling and production were accelerated in 2001 to take advantage of the favorable natural gas price environment.

In the United States, substantially all of the company’s natural gas and natural gas liquids production is sold to its Dynegy affiliate. Please see pages 6 to 7 and 21 to 22 of this Quarterly Report on Form 10-Q for further information relating to the company’s investment in Dynegy.

Quarterly international exploration and production earnings of $710 million declined about 15 percent, mostly the result of lower realizations and higher depreciation expense. These effects were partially offset by lower exploration expense. In the first half of 2002, earnings of $1.547 billion were about 13 percent lower than last year’s first half.

Net oil-equivalent production in the second quarter was essentially unchanged from the year-ago period. The net liquids production component declined about 4 percent to 1,293,000 barrels per day. Production was lower in Indonesia, primarily due to changes in certain production-sharing contract terms. In Nigeria, production declined chiefly as a result of OPEC-related curtailments. The effect of OPEC quotas on Nigerian production in the 2002 quarter was 45,000 barrels per day, versus having no effect in the corresponding 2001 period. Production under certain operating service agreements, which are not included in net working interest production statistics, was curtailed approximately 20,000 barrels per day in this year’s second quarter, compared to about 10,000 barrels per day in the year-ago period. Net natural gas production increased 15 percent to 1.932 billion cubic feet per day. New production from the Philippines, along with higher production in several other countries, contributed to the increase.

Net oil-equivalent production for the first half of 2002 increased about 1 percent from the year-ago period to 1,648,000 barrels per day, primarily the result of increases in gas production. Net natural gas production increased nearly 13 percent to 1.940 billion cubic feet per day. Net liquids production was 1,324,000 barrels per day, down slightly from last year. The effect of OPEC-related curtailments on average daily Nigerian production in the first six months of 2002 was 40,000 barrels per day.

The average natural gas realization for the quarter was $1.94 per thousand cubic feet, compared with $2.39 in the year-ago period. The average natural gas realization for the first half of 2002 was $2.07 per thousand cubic feet, compared with $2.59 last year. The average liquids realization was down about 7 percent to $22.97 per barrel in the second quarter and down 13 percent to $20.99 in the first half of the year.

Earnings for the quarter included net foreign currency losses of $62 million, compared with losses of $33 million in 2001. Currency losses in several countries, particularly Venezuela and Canada, were partially offset by gains attributable to the weakening of the Argentine peso against the U.S. dollar. For the six-month periods, foreign currency gains were $91 million in 2002 and $13 million in 2001. The 2002 period reflected significant gains in the first quarter attributable to the devaluation of the Argentine peso.

U.S. refining, marketing and transportation operating earnings of $56 million declined nearly 90 percent from the year-ago quarter. The decrease was mainly due to significantly lower margins for refined products and the absence in the 2002 quarter of $208 million in earnings from assets that were sold under mandate of the FTC as a condition of the merger. The effect of lower gross margins was partially offset by lower operating expenses.

For the first six months of 2002, operating losses were $98 million, compared with earnings of $720 million in the corresponding 2001 period. In addition to the impact of lower product margins and the absence of about $256 million in earnings from assets sold as a condition of the merger, extensive planned refinery maintenance in this year’s first quarter required product purchases, which further reduced profitability.

The quarter’s average refined product sales realization decreased 15 percent to $33.91 per barrel. Year to date, average refined product sales realizations were $30.45 per barrel, compared with $40.06 last year. Refined product sales volumes, excluding the company’s share of Equilon and Motiva in the 2001 period, decreased 3 percent to 1,681,000 barrels per day, primarily due to a decline in sales of jet and marine fuels. Branded gasoline sales volumes increased about 4 percent to 588,000 barrels per day from the year-ago quarter. For the first half of 2002, refined product sales volumes were 1,619,000 barrels per day, down from 1,664,000 barrels per day in 2001.

Special items in 2002 were for environmental remediation costs and the settlement of a litigation issue with the City of Santa Monica, California. Please see pages 15 and 30 for further information.

International refining, marketing and transportation earnings of $48 million in the second quarter and $141 million in the six months of 2002 both declined about 65 percent from the corresponding periods in 2001. The declines were primarily due to the effects of foreign currency fluctuations, and lower freight rates for the international shipping operations. Margins declined in the Asia-Pacific and European areas of operations but improved slightly in Latin America. Total refined products sales volumes decreased 10 percent to 2,210,000 barrels per day in the second quarter, primarily the result of lower demand for jet fuel and marine fuels. On a year-to-date basis, sales volumes were 2,162,000 barrels per day – also down 10 percent.

Earnings in the 2002 quarter included foreign currency losses of $102 million, compared with gains of $6 million in 2001. For six months, foreign currency losses were $123 million, compared with gains of $61 million in 2001. Currency losses in 2002 occurred mainly in Brazil, New Zealand, Australia, Korea and the United Kingdom.

Chemicals operations earned $36 million in 2002, up $9 million from last year’s second quarter. On a year-to-date basis, chemicals operations earned $51 million, compared with the loss of $10 million posted in last year’s six months. Earnings improved for both the company’s Oronite Division and its 50 percent-owned affiliate, Chevron Phillips Chemical Company LLC. Protracted weak demand for commodity chemicals and industry over-supply conditions continued to suppress earnings for this sector.

All Other activities include the company’s ownership interest in Dynegy, coal mining operations, power and gasification businesses, worldwide cash management and debt financing activities, corporate administrative costs, insurance operations, real estate activities and technology investments. Net operating charges for the second quarter 2002, were $165 million, $104 million lower than in 2001. For the six-month periods, net operating charges of $329 million in 2002 were $157 lower than in the 2001 period.

The company’s share of operating earnings from Dynegy were $3 million in the 2002 quarter, down from $35 million in 2001. For the six months, operating earnings from Dynegy were $43 million, down from $69 million in 2001.

Coal mining operations earned $1 million in the second quarter of 2002, compared with $7 million in last year’s second quarter. Six-month operating earnings were $6 million in 2002, down from $13 million last year.

Power and gasification incurred losses of $15 million for the quarter and $17 million for the six months in 2002. Losses of $9 million and $27 million were recorded in the corresponding 2001 periods.

Net operating charges from other activities were $154 million in the second quarter 2002, compared with $302 million in the 2001 period. The 2002 period benefited from the effect of lower income tax expense and corporate charges. For the six-month periods, net operating charges from other activities were $361 million in 2002 and $541 million in 2001. In addition to the benefits indicated in the 2002 second quarter, the six-month period also benefited from lower net interest expense.

Special items in the 2002 quarter included charges of $531 million for the write-down of the company’s investment in Dynegy, $100 million for the company’s share of Dynegy’s own write-downs and other adjustments, and $24 million for environmental remediation costs. In the first quarter 2002, special items included $74 million for the company’s share of Dynegy’s write-down of its investments in telecommunications businesses. For further information related to the company’s investment in Dynegy, please see “Information Relating to the Company’s Investment in Dynegy” on pages 6 to 7 and pages 21 to 22 of this Quarterly Report on
Form 10-Q.

Merger-related expenses reduced net income by $73 million in the second quarter 2002, compared to $36 million in 2001. For the six-month 2002 and 2001 periods, the effect of merger-related expenses on net income was $205 million and $57 million, respectively.

Foreign currency gains were $21 million in the second quarter of 2002, compared with gains of $8 million in 2001. For six months, foreign currency gains were $21 million, compared with losses of $2 million in 2001.

Cash, cash equivalents and marketable securities totaled $3.4 billion at June 30, 2002 – a $0.3 billion increase from year-end 2001. Cash provided by operating activities was $3.7 billion in the first half of 2002, compared with $7.1 billion in the year-ago period. The 2002 amount was adversely affected by lower crude oil and natural gas prices and reduced refined product margins. During the first half of 2002, the company received proceeds of $2.2 billion, including dividends due, from the sale of the company’s investments in Equilon and Motiva. These proceeds, in addition to cash provided by operating activities in the first half of 2002, enabled the company to fund its capital program, to pay dividends to stockholders, and to reduce overall debt levels.

During the first six months of 2002, the company paid dividends of $1.494 billion to common stockholders. On July 31, 2002, ChevronTexaco declared a quarterly dividend of 70 cents per share, unchanged from the preceding quarter, payable on September 10, 2002.

At the end of the 2002 second quarter, ChevronTexaco had $3.2 billion in committed credit facilities with various major banks, which permit the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and also can be used for general credit requirements. No borrowings were outstanding under these facilities at June 30, 2002. At the end of July, the total of these committed credit facilities had increased to approximately $4.4 billion. During the second quarter, the company increased the total value of “shelf” registrations on file with the Securities and Exchange Commission (SEC) by $2 billion. The company currently has three existing “shelf” registrations on file with the SEC that together would permit registered debt offerings of up to $4.8 billion of debt securities. At June 30, 2002, the company also had lines of credit available for short-term financing totaling $500 million, of which $330 million had not been used.

ChevronTexaco’s total debt and capital lease obligations were $16.8 billion at June 30, 2002, down from $17.4 billion at year-end 2001. In the first six months of 2002, net repayments of $662 million in long-term debt and other financial obligations were slightly offset by proceeds of $107 million from net additional short-term debt. Changes in long-term debt included a $250 million repayment of Texaco North Sea U.K. notes, a $192 million repayment of New Zealand debt, and a $100 million repayment of ChevronTexaco Corporation 8.11 percent notes. Also included in the decline in the company’s long-term debt levels was a non-cash reduction of $100 million of ESOP debt. Proceeds from new long-term debt issuances were $57 million. In July, the company redeemed $200 million of Texaco Capital Inc. 8.375 percent bonds due 2022. The redemption premium was 3.67 percent.

The company’s debt due within 12 months, consisting primarily of commercial paper and the current portion of long-term debt, totaled $11.3 billion at June 30, 2002, down from $11.6 billion at December 31, 2001. Of this

total, $4.2 billion and $3.2 billion were reclassified to long-term at the end of each period, respectively. Settlement of these obligations was not expected to require the use of working capital in 2002, 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 refinance its commercial paper continually, maintaining levels it believes to be appropriate.

In July 2002, the company acquired $125 million in cumulative preferred shares of Chevron Phillips Chemical Company, its 50 percent-owned affiliate.

For information concerning the company’s investment in Dynegy, please see “Information Relating to the Company’s Investment in Dynegy” on pages 6 to 7 and pages 21 to 22 of this Quarterly Report on Form 10-Q.

The company benefits from lower interest rates available on short-term debt; however, ChevronTexaco’s proportionately large amount of short-term debt keeps its ratio of current assets to current liabilities at relatively low levels. Current assets also include inventories valued on a Last-In-First-Out (LIFO) basis, which are significantly lower than current costs in all periods presented. The current ratio was 0.9 at June 30, 2002, about the same level as at year-end 2001.

ChevronTexaco’s debt ratio (total debt to total-debt-plus-equity) was 33 percent at June 30, 2002, about the same as at year-end 2001. The company continually monitors its spending levels, market conditions and related interest rates to maintain what it perceives to be reasonable debt levels.

The company’s future debt level is dependent primarily on its results of operations, its capital-spending program and cash that may be generated from asset dispositions. The company believes it has borrowing capacity to meet unanticipated cash requirements. Additionally, the company believes that during periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, it has the flexibility to increase borrowings and/or modify capital spending plans to enable maintaining the common stock dividend and the company’s high-quality debt ratings.

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

Worldwide capital and exploratory expenditures, including the company’s share of affiliates’ expenditures, were $4.3 billion in the first half of 2002, compared with $5.1 billion in last year’s first half. Expenditures for international exploration and production projects were $2.3 billion – 52 percent of the total expenditures – reflecting the company’s continued emphasis on increasing international oil and gas production. Capital expenditures in this year’s first half included more than $400 million for the acquisition of assets associated with the Captain Field in the North Sea that were previously leased and an approximate $200 million additional investment in the company’s Dynegy affiliate. In the first half of 2001, expenditures included the acquisition of an additional 5 percent interest in the Tengizchevroil affiliate and higher development spending in the Gulf of Mexico, related to natural gas production.

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 reformulated gasoline, which ChevronTexaco sells 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 in infringement 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 from August 1, 1996, to September 30, 2000. Additionally, the U.S. Patent and Trademark Office (USPTO) granted a motion by the refiners to re-examine the validity of Unocal’s patent. The District Court judge requested further briefing and advised that she would not enter final judgement in this case until the USPTO had completed its reexamination of the ‘393’ patent. During 2002 the USPTO rejected the validity of the ‘393’ patent and another Unocal patent, the ‘126’ patent, which could affect a larger share of U.S. gasoline production. Separately, the U.S. Federal Trade Commission has also announced that it is investigating whether Unocal’s conduct in this matter was unfair competition, which may make Unocal’s patent unenforceable.

Unocal has obtained additional patents that could affect a larger share of U.S. gasoline production. ChevronTexaco believes these additional patents are invalid, unenforceable, and/or not infringed. The company’s financial exposure in the event of unfavorable conclusions to the patent litigation and regulatory reviews may include royalties, plus interest, for production of gasoline that is proved to have infringed the patents. The competitive and financial effects on the company’s refining and marketing operations, while presently indeterminable, could be material. ChevronTexaco – as well as Chevron and Texaco separately pre-merger – 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 $28 million for the original court ruling, including interest and fees.

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, ChevronTexaco is a party to lawsuits and claims related to the use of the chemical MTBE in certain oxygenated gasolines. These actions may require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims

related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. In July 2002, ChevronTexaco and Exxon Mobil Corp. (ExxonMobil) reached a settlement of an MTBE-related litigation matter with the City of Santa Monica, California. Under the terms of the settlement, ChevronTexaco and ExxonMobil guaranteed to fund the cost of building and operating a water treatment facility to remove MTBE and other contaminants from certain water wells and to pay a cash settlement to cover costs of alleged contamination. The City of Santa Monica agreed to release ChevronTexaco and ExxonMobil from a lawsuit filed in 2000 against a group of oil refiners, suppliers, and owners and operators of pipelines and other facilities for allegedly contaminating water wells with MTBE. The settlement also states that ChevronTexaco and ExxonMobil may be repaid a portion of the construction and operating costs if the City of Santa Monica fully recovers funds from the other companies named in the suit. ChevronTexaco has worked to reduce the use of MTBE in gasoline it manufactures in the United States. The State of California has directed that MTBE be phased out of the manufacturing process by the end of 2003, and the company intends to comply with this mandate.

The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemical or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including but not limited to: Superfund sites and refineries, oil fields, service stations, terminals, and land development areas, whether operating, closed or sold. The amount of such future cost is indeterminable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. While the company has provided for known environmental obligations that are probable and reasonably

estimable, the amount of 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.

For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated oil and gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for ChevronTexaco’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills in California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. ChevronTexaco currently estimates its maximum possible net before-tax liability at less than $400 million. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at more than $200 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

Effective July 15, 2002, a consensus (Consensus 02-3) of the FASB Emerging Issues Task Force (EITF) will require companies involved in energy trading and risk management activities to present the gains and losses stemming from those activities on a net basis in the income statement. The company is currently evaluating these reclassification requirements, which will have no impact on net income.

In July, the FASB has issued Statement No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. The statement replaces EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” FAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.

On August 7, 2002, ChevronTexaco filed a Current Report on Form 8-K reporting compliance by its Chief Executive Officer and its Chief Financial Officer with Securities and Exchange Commission Emergency Order 4-460, requiring certification of reports filed by ChevronTexaco earlier this year. The certification by such officers of this Quarterly Report on Form 10-Q, as required by Section 906 of the Sarbanes-Oxley Act of 2002, has been submitted to the SEC as additional correspondence accompanying this report.

Richmond Refinery — Notices of Violation, Bay Area Air Quality Management District

Chevron Products Company’s (a division of Chevron U.S.A.) Richmond, California, refinery has been issued approximately 35 Notices of Violation during the calendar years 2001 and 2002, which allege non-compliance with the regulations of the Bay Area Air Quality Management District. The Notices of Violation address a variety of issues related to air emissions including, but not limited to, leaks of volatile organic compounds from the facility’s processing equipment. The company has determined that the Notices of Violation will likely result in the payment of a civil penalty in excess of $100,000.

The following matters were submitted to a vote of stockholders at the Annual Meeting on May 15, 2002.

Voters elected fifteen incumbent directors for one-year terms. The vote tabulation for individual directors was:

Voters approved the appointment of PricewaterhouseCoopers LLP as the company’s independent accountants by a vote of 828,578,905 (96.55 percent) for and 29,616,962 (3.45 percent) against. There were also 5,747,753 abstentions.

Voters approved the performance-based provisions of the Management Incentive Plan by a vote of 781,694,519 (91.56 percent) for and 72,013,438 (8.44 percent) against. There were 10,206,205 abstentions.

Voters approved the performance-based provisions of the Long-Term Incentive Plan by a vote of 754,785,336 (88.45 percent) for and 98,604,456 (11.55 percent) against. There were 10,524,974 abstentions.

A stockholder proposal to eliminate Bioaccumulative Halogenated Pollutants was rejected. There were 37,083,197 votes (5.40 percent) for the proposal and 650,230,566 votes (94.60 percent) against. There were also 25,701,984 abstentions.

A stockholder proposal to report on potential environmental damage to the Arctic National Wildlife Refuge was rejected. There were 52,396,610 votes (7.64 percent) for the proposal and 633,461,602 votes (92.36 percent) against. There were also 27,143,603 abstentions.

A stockholder proposal to submit the stockholder rights plan to a stockholder vote was rejected. There were 345,220,127 votes (49.37 percent) for the proposal and 354,068,712 votes (50.63 percent) against. There were also 13,698,372 abstentions.

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.


Class		Outstanding as of June 30, 2002

Common stock, $.75 par value		1,068,073,461


PART I. FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONSOLIDATED STATEMENT OF INCOME
		CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
		CHEVRONTEXACO CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET
		CHEVRONTEXACO CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	Item 2MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PART II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURE
Quarterly Report for Period Ended June 30, 2002
Exhibit 12.1


		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		1
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statement of Income for the three months and six months ended June 30, 2002 and 2001		2
	Consolidated Statement of Comprehensive Income for the three months and six months ended June 30, 2002 and 2001		3
	Consolidated Balance Sheet at June 30, 2002 and December 31, 2001		4
	Consolidated Statement of Cash Flows for the six months ended June 30, 2002 and 2001		5
	Notes to Consolidated Financial Statements		6-17
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18-32
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings		33
Item 4.	Submission of Matters to a Vote of Security Holders		33
Item 6.	Listing of Exhibits and Reports on Form 8-K		34
	Signature		34
Exhibit	Computation of Ratio of Earnings to Fixed Charges		36



		Three Months Ended					Six Months Ended
		June 30					June 30

Millions of Dollars, Except Per-Share Amounts		2002		2001			2002		2001

Revenues and Other Income
Sales and other operating revenues¹		$	25,223	$	29,031		$	46,067	$	58,061
Income from equity affiliates			81		574			193		862
Other income			29		89			228		216

	Total Revenues and Other Income		25,333		29,694			46,488		59,139

Costs and Other Deductions
Purchased crude oil and products			14,694		17,288			26,507		34,168
Operating expenses			1,699		1,843			3,451		3,722
Selling, general and administrative expenses			1,153		887			2,016		1,785
Exploration expenses			135		249			220		411
Depreciation, depletion and amortization			1,241		1,168			2,446		2,325
Write-down of Dynegy investment			702		—			702		—
Merger-related expenses			119		48			302		73
Taxes other than on income¹			4,137		3,941			7,917		7,898
Interest and debt expense			160		217			307		476
Minority interest			10		34			22		72

	Total Costs and Other Deductions		24,050		25,675			43,890		50,930

Income Before Income Tax Expense			1,283		4,019			2,598		8,209
Income Tax Expense			876		1,911			1,466		3,668

Net Income		$	407	$	2,108		$	1,132	$	4,541

Per Share of Common Stock:
	Net Income – Basic	$	.39	$	1.99		$	1.07	$	4.29
– Diluted		$	.39	$	1.99		$	1.07	$	4.28
Dividends		$	.70	$	.65	²	$	1.40	$	1.30	²
Weighted Average Number of Shares Outstanding (000s) – Basic			1,060,434		1,060,023			1,060,258		1,059,332
– Diluted			1,062,289		1,063,679			1,062,150		1,062,454
¹ Includes consumer excise taxes:		$	1,751	$	1,772		$	3,439	$	3,554
² Chevron dividend pre-merger



				Three Months Ended						Six Months Ended
				June 30						June 30

Millions of Dollars				2002			2001			2002			2001

Net Income				$	407		$	2,108		$	1,132		$	4,541

Other Comprehensive (Loss) Gain
	Currency translation adjustment				27			(15	)		10			(13	)

	Unrealized holding gains on securities:
		Net (loss) gain arising during period
			Before income taxes		(297	)		(3	)		(200	)		9
			Income taxes		104			—			70			—
		Reclassification to net income of net recognized loss
			Before income taxes		217			—			217			—
			Income taxes		(76	)		—			(76	)		—

	Total				(52	)		(3	)		11			9

	Net derivatives gain on equity investees’ hedge transactions:
			Before income taxes		56			27			63			8
			Income taxes		(20	)		(9	)		(22	)		(3	)

	Total				36			18			41			5

	Minimum pension liability adjustment:
			Before income taxes		(85	)		—			(85	)		14
			Income taxes		31			—			31			(5	)

	Total				(54	)		—			(54	)		9

Other Comprehensive (Loss) Gain					(43	)		—			8			10

Comprehensive Income				$	364		$	2,108		$	1,140		$	4,551

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Delaware (State or other jurisdiction of incorporation or organization)		94-0890210 (I.R.S. Employer Identification Number)		575 Market Street, San Francisco, California 94105 --------------------------------------------------- (Address of principal executive offices) (Zip Code)


			At June 30			At December 31
Millions of Dollars			2002			2001

			(Unaudited)
ASSETS
Cash and cash equivalents			$	2,652		$	2,117
Marketable securities				763			1,033
Accounts and notes receivable				8,937			8,279
Inventories:
	Crude oil and petroleum products			2,216			2,207
	Chemicals			191			209
	Materials, supplies and other			537			532

		Total inventories		2,944			2,948
Prepaid expenses and other current assets				2,408			1,769
Assets held for sale – merger related				—			2,181

		Total Current Assets		17,704			18,327
Long-term receivables				1,386			1,225
Investments and advances				12,139			12,252
Properties, plant and equipment, at cost				102,406			99,943
Less: accumulated depreciation, depletion and amortization				58,627			56,710

		Properties, plant and equipment, net		43,779			43,233
Deferred charges and other assets				2,634			2,535

		Total Assets	$	77,642		$	77,572

LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt			$	7,070		$	8,429
Accounts payable				7,010			6,427
Accrued liabilities				3,064			3,399
Federal and other taxes on income				1,816			1,398
Other taxes payable				1,082			1,001

		Total Current Liabilities		20,042			20,654
Long-term debt				9,432			8,704
Capital lease obligations				266			285
Deferred credits and other noncurrent obligations				4,454			4,394
Noncurrent deferred income taxes				6,052			6,132
Reserves for employee benefit plans				3,354			3,162
Minority interests				286			283

		Total Liabilities		43,886			43,614

Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued)				—			—
Common stock (authorized 4,000,000,000 shares, $.75 par value, 1,137,021,057 shares issued)				853			853
Capital in excess of par value				4,827			4,811
Retained earnings				32,409			32,767
Accumulated other comprehensive loss				(298	)		(306	)
Deferred compensation and benefit plan trust				(652	)		(752	)
Treasury stock, at cost (68,947,596 and 69,800,315 shares at June 30, 2002 and December 31, 2001, respectively)				(3,383	)		(3,415	)

		Total Stockholders’ Equity		33,756			33,958

		Total Liabilities and Stockholders’ Equity	$	77,642		$	77,572


*	2001 includes segment reclassifications to conform to 2002 presentation.


Millions of dollars	Amount

Additions – 2001	$	891
Payments – 2001		(105	)

Balance at December 31, 2001		786
Additions – 2002		13
Payments – 2002		(372	)

Balance at June 30, 2002	$	427


Directors	Shares For		Shares Withheld

S. H. Armacost		851,784,428		12,155,584
R. J. Eaton		852,357,831		11,582,181
S. L. Ginn		847,125,344		16,814,668
C. A. Hills		846,394,397		17,545,615
F. G. Jenifer		846,609,348		17,330,664
J. B. Johnston		851,726,618		12,213,394
S. Nunn		838,962,946		24,977,066
D. J. O’Reilly		852,943,974		10,996,038
P. J. Robertson		852,762,326		11,177,686
C. R. Shoemate		852,429,783		11,510,229
F. A. Shrontz		851,794,289		12,145,723
G. F. Tilton		851,904,572		12,035,440
T. A. Vanderslice		845,770,618		18,169,394
C. Ware		846,519,850		17,420,162
J. A. Young		851,885,519		12,054,493


(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)		Computation of Ratio of Earnings to Fixed Charges


		CHEVRONTEXACO CORPORATION (Registrant)

Date August 9, 2002		/s/ S. J. CROWE S. J. Crowe, Vice President and Comptroller (Principal Accounting Officer and Duly Authorized 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)	Computation of Ratio of Earnings to Fixed Charges



			Three Months Ended						Six Months Ended
			June 30						June 30

Millions of Dollars			2002			2001			2002			2001

Exploration and Production
	United States*		$	2,507		$	4,329		$	4,593		$	10,404
	International			3,712			4,879			6,929			8,832

		Sub-total		6,219			9,208			11,522			19,236
	Intersegment Elimination – United States			(1,276	)		(883	)		(2,088	)		(1,732	)
	Intersegment Elimination – International			(2,357	)		(2,682	)		(4,206	)		(4,267	)

Total Exploration and Production				2,586			5,643			5,228			13,237

Refining, Marketing and Transportation
	United States			9,732			9,609			16,885			18,447
	International			12,442			13,201			23,210			25,306

		Sub-total		22,174			22,810			40,095			43,753
	Intersegment Elimination – United States			(39	)		(54	)		(79	)		(129	)
	Intersegment Elimination – International			(18	)		(52	)		(132	)		(171	)

Total Refining, Marketing and Transportation				22,117			22,704			39,884			43,453

Chemicals
	United States			108			103			214			195
	International			181			199			354			393

		Sub-total		289			302			568			588
	Intersegment Elimination – United States			(26	)		(21	)		(49	)		(43	)
	Intersegment Elimination – International			(16	)		(31	)		(34	)		(55	)

Total Chemicals				247			250			485			490

All Other
	United States*			330			435			564			882
	International			5			13			10			27



			Three Months Ended				Six Months Ended
			June 30				June 30

			2002		2001		2002		2001

U.S. Exploration and Production
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			627		616		623		613
	Net Natural Gas Production (MMCFPD)			2,504		2,783		2,506		2,835
	Sales of Natural Gas (MMCFPD)³			5,125		8,499		5,980		8,708
	Sales of Natural Gas Liquids (MBPD)			223		316		254		340
	Revenue from Net Production
		Crude Oil ($/Bbl.)	$	23.05	$	23.22	$	20.22	$	23.81
		Natural Gas ($/ MCF)	$	3.04	$	4.80	$	2.66	$	6.18
International Exploration and Production
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			1,293		1,342		1,324		1,341
	Net Natural Gas Production (MMCFPD)			1,932		1,675		1,940		1,724
	Sales of Natural Gas (MMCFPD)			3,168		2,360		3,377		2,377
	Sales of Natural Gas Liquids (MBPD)			138		105		134		101
	Revenue from Liftings
		Liquids ($/Bbl.)	$	22.97	$	24.79	$	20.99	$	24.12
		Natural Gas ($/MCF)	$	1.94	$	2.39	$	2.07	$	2.59
	Other Produced Volumes (MBPD)⁴			94		104		95		108
U.S. Refining, Marketing and Transportation ⁵
	Sales of Gasoline (MBPD)⁶			772		725		735		696
	Sales of Other Refined Products (MBPD)			909		1,008		884		968
	Refinery Input (MBPD)			1,041		1,009		955		952
	Average Refined Product Sales Price ($/ Bbl.)		$	33.91	$	39.80	$	30.45	$	40.06
International Refining, Marketing and Transportation
	Sales of Refined Products (MBPD)			2,210		2,463		2,162		2,410
	Refinery Input (MBPD)			1,115		1,132		1,141		1,138



			Three Months Ended				Six Months Ended
			June 30				June 30

Millions of Dollars			2002		2001		2002		2001

United States
	Exploration and Production		$	444	$	656	$	819	$	1,233
	Refining, Marketing and Transportation			148		203		258		366
	Chemicals			44		53		71		66
	All Other			172		470		498		563

		Total United States		808		1,382		1,646		2,228

International
	Exploration and Production			1,113		995		2,268		2,475
	Refining, Marketing and Transportation			231		228		383		403
	Chemicals			7		8		10		12
	All Other			14		2		16		3

		Total International		1,365		1,233		2,677		2,893

		Worldwide	$	2,173	$	2,615	$	4,323	$	5,121