Chevron (CVX) 10-Q 2004 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2004
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-368-2

ChevronTexaco Corporation

(Exact name of registrant as specified in its charter)

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)

Registrant’s telephone number, including area code: (925) 842-1000

NONE

(Former name or former address, if changed since last 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:

Class	Outstanding as of June 30, 2004
Common stock, $.75 par value	1,065,074,416

INDEX

		Page
		No.
	Cautionary Statements Relevant to Forward-Looking Information for the Purpose of “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		2
PART I  FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements —
	Consolidated Statement of Income for the Three and Six Months Ended June 30, 2004 and 2003		3
	Consolidated Statement of Comprehensive Income for the Three and Six Months Ended June 30, 2004 and 2003		4
	Consolidated Balance Sheet at June 30, 2004, and December 31, 2003		5
	Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2004 and 2003		6
	Notes to Consolidated Financial Statements		7-22
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23-41
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		41
Item 4.	Controls and Procedures		41
PART II  OTHER INFORMATION
Item 1.	Legal Proceedings		42
Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		42
Item 5.	Other Information		42
Item 6.	Exhibits and Reports on Form 8-K		43
Signature			44
Exhibits: Computation of Ratio of Earnings to Fixed Charges			46
Rule 13a-14(a)/15d-14(a) Certifications			47-48
Section 1350 Certifications			49-50
EXHIBIT 12.1
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2

1

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE

PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

     Among the factors that could cause actual results to differ materially are crude oil and natural gas prices; refining margins and marketing margins; chemicals prices and competitive conditions affecting supply and demand for aromatics, olefins and additives products; actions of competitors; the competitiveness of alternate energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; 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 complete 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.

2

PART I.

FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

CHEVRONTEXACO CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF INCOME

(Unaudited)

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2004		2003		2004		2003
			(Millions of dollars, except per share amounts)
Revenues and Other Income
Sales and other operating revenues(1)			$	36,624	$	28,994	$	69,708	$	59,564
Income from equity affiliates				740		215		1,184		480
Other income				937		62		1,082		109
	Total Revenues and Other Income			38,301		29,271		71,974		60,153
Costs and Other Deductions
Purchased crude oil and products				22,530		17,257		42,626		35,522
Operating expenses				2,243		1,842		4,406		3,769
Selling, general and administrative expenses				986		1,061		2,007		2,070
Exploration expenses				164		147		249		302
Depreciation, depletion and amortization				1,251		1,377		2,453		2,603
Taxes other than on income(1)				4,884		4,508		9,639		8,827
Interest and debt expense				93		118		187		248
Minority interests				18		20		40		42
	Total Costs and Other Deductions			32,169		26,330		61,607		53,383
Income From Continuing Operations Before Income Tax Expense				6,132		2,941		10,367		6,770
Income tax expense				2,050		1,361		3,761		3,095
Income From Continuing Operations				4,082		1,580		6,606		3,675
Income From Discontinued Operations				43		20		81		41
Income Before Cumulative Effect of Changes in Accounting Principles				4,125		1,600		6,687		3,716
Cumulative effect of changes in accounting principles				—		—		—		(196	)
Net Income			$	4,125	$	1,600	$	6,687	$	3,520
Per Share of Common Stock:
	Income From Continuing Operations
		— Basic	$	3.84	$	1.49	$	6.21	$	3.46
		— Diluted	$	3.84	$	1.48	$	6.20	$	3.45
	Income From Discontinued Operations
		— Basic	$	0.04	$	0.02	$	0.08	$	0.04
		— Diluted	$	0.04	$	0.02	$	0.08	$	0.04
	Cumulative Effect of Changes in Accounting Principles
		— Basic		—		—		—	$	(0.18	)
		— Diluted		—		—		—	$	(0.18	)
	Net Income
		— Basic	$	3.88	$	1.51	$	6.29	$	3.32
		— Diluted	$	3.88	$	1.50	$	6.28	$	3.31
	Dividends		$	0.73	$	0.70	$	1.46	$	1.40
	Weighted Average Number of Shares Outstanding (000s)
		— Basic		1,061,397		1,062,256		1,062,403		1,062,137
		— Diluted		1,064,696		1,063,709		1,065,438		1,063,655

(1) Includes consumer excise taxes: $ 1,921 $ 1,765 $ 3,778 $ 3,456

See accompanying notes to consolidated financial statements.

3

CHEVRONTEXACO CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Unaudited)

			Three Months Ended						Six Months Ended
			June 30,						June 30,
			2004			2003			2004			2003
			(Millions of dollars)
Net Income			$	4,125		$	1,600		$	6,687		$	3,520
	Currency translation adjustment			5			15			6			11
	Unrealized holding gain (loss) on securities			(6	)		304			1			293
	Net derivatives (loss) gain on hedge transactions:
		Before income taxes		(23	)		101			(21	)		109
		Income taxes		—			(37	)		—			(40	)
		Total		(23	)		64			(21	)		69
	Minimum pension liability adjustment			3			—			3			(17	)
Other Comprehensive (Loss) Income, net of tax				(21	)		383			(11	)		356
Comprehensive Income			$	4,104		$	1,983		$	6,676		$	3,876

See accompanying notes to consolidated financial statements.

4

CHEVRONTEXACO CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

					At June 30,			At December 31,
					2004			2003
					(Millions of dollars, except
					per-share amounts)
ASSETS
Cash and cash equivalents					$	8,339		$	4,266
Marketable securities						998			1,001
Accounts and notes receivable, net						11,666			9,722
Inventories:
	Crude oil and petroleum products					2,580			2,003
	Chemicals					163			173
	Materials, supplies and other					458			472
		Total inventories				3,201			2,648
Prepaid expenses and other current assets						1,841			1,789
		Total Current Assets				26,045			19,426
Long-term receivables, net						1,354			1,493
Investments and advances						13,330			12,319
Properties, plant and equipment, at cost						100,304			100,556
Less: accumulated depreciation, depletion and amortization						56,111			56,018
		Properties, plant and equipment, net				44,193			44,538
Deferred charges and other assets						2,496			2,594
Assets held for sale						1,145			1,100
			Total Assets		$	88,563		$	81,470
LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt					$	1,803		$	1,703
Accounts payable						10,031			8,675
Accrued liabilities						2,901			3,172
Federal and other taxes on income						3,030			1,392
Other taxes payable						1,226			1,169
		Total Current Liabilities				18,991			16,111
Long-term debt						10,089			10,651
Capital lease obligations						233			243
Deferred credits and other noncurrent obligations						7,852			7,758
Noncurrent deferred income taxes						6,801			6,417
Reserves for employee benefit plans						3,379			3,727
Minority interests						192			268
		Total Liabilities				47,537			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 June 30, 2004 and December 31, 2003, respectively)						853			853
Capital in excess of par value						4,915			4,855
Retained earnings						40,455			35,315
Accumulated other comprehensive loss						(820	)		(809	)
Deferred compensation and benefit plan trust						(576	)		(602	)
Treasury stock, at cost (71,941,591 and 67,873,337 shares at June 30, 2004 and December 31, 2003, respectively)						(3,801	)		(3,317	)
		Total Stockholders’ Equity				41,026			36,295
				Total Liabilities and Stockholders’ Equity	$	88,563		$	81,470

See accompanying notes to consolidated financial statements.

5

CHEVRONTEXACO CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

				Six Months Ended
				June 30,
				2004			2003
				(Millions of dollars)
Operating Activities
	Net income			$	6,687		$	3,520
	Adjustments
		Cumulative effect of changes in accounting principles			—			196
		Depreciation, depletion and amortization			2,453			2,603
		Dry hole expense			106			142
		Distributions less than income from equity affiliates			(906	)		(309	)
		Net before-tax gains on asset retirements and sales			(948	)		(28	)
		Net foreign currency effects			(2	)		72
		Deferred income tax provision			294			124
		Net decrease in operating working capital			264			340
		Minority interest in net income			40			42
		Decrease in long-term receivables			128			53
		Decrease in other deferred charges			558			228
		Cash contributions to employee pension plans			(594	)		(57	)
		Other			(149	)		161
			Net Cash Provided by Operating Activities		7,931			7,087
Investing Activities
	Capital expenditures				(2,974	)		(2,622	)
	Proceeds from asset sales				1,500			165
	Net sales of marketable securities				3			303
	Repayment of loans by equity affiliates				75			18
			Net Cash Used for Investing Activities		(1,396	)		(2,136	)
Financing Activities
	Net borrowings (payments) of short-term obligations				35			(3,356	)
	Proceeds from issuance of long-term debt				—			1,032
	Repayments of long-term debt and other financing obligations				(421	)		(1,077	)
	Cash dividends				(1,550	)		(1,485	)
	Dividends paid to minority interests				(3	)		(25	)
	Net (purchases) sales of treasury shares				(423	)		39
			Net Cash Used For Financing Activities		(2,362	)		(4,872	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents					(100	)		56
Net Change in Cash and Cash Equivalents					4,073			135
Cash and Cash Equivalents at January 1					4,266			2,957
Cash and Cash Equivalents at June 30				$	8,339		$	3,092

See accompanying notes to consolidated financial statements.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Interim Financial 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 15.

     Certain notes and other information have been condensed or omitted from the interim financial statements presented in this Quarterly Report on Form 10-Q. Therefore, these financial statements should be read in conjunction with the company’s 2003 Annual Report on Form 10-K.

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

Note 2. Net Income

     Net income for the second quarter 2004 was $4.1 billion. Included in this amount were a gain of $585 million related to the sale of upstream assets in western Canada and a one-time benefit of $255 million associated with changes in income-tax laws in certain international operations. Also included was income of $43 million associated with certain assets that were classified as discontinued operations because of their pending sale. Discontinued operations and assets held for sale are discussed in Note 3.

     Net income for the second quarter 2003 was $1.6 billion. Included in this amount were special charges of $117 million, mainly for the write-down of assets in anticipation of their sale, and income of $20 million from discontinued operations.

     Net income for the first six months of 2004 was $6.7 billion. Besides the second quarter items, the year-to-date amount included $81 million from discontinued operations and a first quarter charge of $55 million for an adverse litigation ruling.

     Net income for the first six months of 2003 was $3.5 billion. Besides the second quarter items, the year-to-date results also included 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 $41 million from discontinued operations. The cumulative effect of changes in accounting principles is discussed in Note 15.

     Foreign currency effects increased earnings by $45 million in the second quarter of 2004, but reduced earnings by $157 million in the year-ago quarter. For the first six-months of 2004, foreign currency effects increased earnings by $2 million but reduced earnings by $202 million in the corresponding 2003 period.

Note 3. Assets Held for Sale and Discontinued Operations

     At June 30, 2004, and December 31, 2003, the company classified $1.1 billion 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 amounts at June 30, 2004, and December 31, 2003, were approximately 150 U.S. upstream onshore properties accounted for as discontinued operations. In May 2004, the company reached an agreement to sell these assets to XTO Energy Inc. for $1.1 billion. The transaction is expected to close in the third quarter 2004.

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2004		2003		2004		2003
	(Millions of dollars)
Revenues and other income	$	90	$	90	$	176	$	173
Income from discontinued operations before income tax expense		70		31		130		66
Income from discontinued operations, net of tax		43		20		81		41

     The western Canada upstream assets sold in the second quarter 2004 (discussed in Note 2) were not classified as discontinued operations under the applicable accounting rules because the company has contracted to purchase a portion of the crude oil and natural gas volumes from those assets to help fulfill supply and transportation commitments and to provide feedstock for a company refinery.

Note 4. Information Relating to the Statement of Cash Flows

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

		Six Months Ended
		June 30,
		2004			2003
		(Millions of dollars)
Increase in accounts and notes receivable		$	(1,938	)	$	(200	)
Increase in inventories			(563	)		(164	)
Decrease in prepaid expenses and other current assets			36			41
Increase (decrease) in accounts payable and accrued liabilities			1,062			(264	)
Increase in income and other taxes payable			1,667			927
	Net decrease in operating working capital	$	264		$	340

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

	Six Months Ended
	June 30,
	2004		2003
	(Millions of dollars)
Interest on debt (net of capitalized interest)	$	195	$	249
Income taxes		1,875		2,070

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

		Six Months Ended
		June 30,
		2004			2003
		(Millions of dollars)
Marketable securities purchased		$	(622	)	$	(2,767	)
Marketable securities sold			625			3,070
	Net sales of marketable securities	$	3		$	303

     The 2004 “Net Cash Provided by Operating Activities” included a $339 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.”

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The “Net (purchases) sales of treasury shares” in 2004 included share repurchases of $600 million related to the company’s common stock repurchase program which were partially offset by the issuance of shares for the exercise of stock options.

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

		Six Months Ended
		June 30,
		2004			2003
		(Millions of dollars)
Additions to properties, plant and equipment		$	2,699		$	2,373
Additions to investments			241			238
Current year dry hole expenditures			86			68
Payments for other liabilities and assets, net			(52	)		(57	)
	Capital expenditures		2,974			2,622
Other exploration expenditures			144			161
Payments of long-term debt and other financing obligations(1)			1			268
	Capital and exploratory expenditures, excluding equity affiliates	$	3,119		$	3,051
Equity in affiliates’ expenditures			636			403
	Capital and exploratory expenditures, including equity affiliates	$	3,755		$	3,454

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

Note 5. Operating Segments and Geographic Data

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

     The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) (terms as defined in FAS 131). The CODM is the company’s Executive Committee, a committee of senior officers that includes the chief executive officer, and which in turn reports to the Board of Directors of ChevronTexaco Corporation.

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

     Segment managers for the reportable segments are directly accountable to, and maintain regular contact with, the company’s CODM to discuss the segment’s operating activities and financial performance. The CODM approves annual capital and exploratory budgets at the reportable segment level, as well as approves capital and exploratory funding for major projects and approves major changes to the annual capital and exploratory budgets. However, business-unit managers within the operating segments are directly responsible for decisions relating to project implementation and all other matters connected with daily operations.

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 from continuing operations for the three-month and six-month periods ended June 30, 2004 and 2003, is presented in the following table:

Segment Income

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2004			2003			2004			2003
		(Millions of dollars)
Income from Continuing Operations
Upstream — Exploration and Production
	United States	$	912		$	638		$	1,734		$	1,633
	International		2,028			624			3,153			1,581
Total Exploration and Production			2,940			1,262			4,887			3,214
Downstream — Refining, Marketing and Transportation
	United States		517			187			793			257
	International		527			251			891			496
Total Refining, Marketing and Transportation			1,044			438			1,684			753
Chemicals
	United States		40			9			89			(11	)
	International		19			25			44			48
Total Chemicals			59			34			133			37
Total Segment Income			4,043			1,734			6,704			4,004
All Other
	Interest Expense		(60	)		(88	)		(119	)		(184	)
	Interest Income		24			19			45			37
	Other		75			(85	)		(24	)		(182	)
Income from Continuing Operations			4,082			1,580			6,606			3,675
Income from Discontinued Operations			43			20			81			41
Cumulative Effect of Changes in Accounting Principles			—			—			—			(196	)
Net Income		$	4,125		$	1,600		$	6,687		$	3,520

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     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 June 30, 2004, and year-end 2003 follow:

Segment Assets

		At June 30,		At December 31,
		2004		2003
		(Millions of dollars)
Upstream — Exploration and Production
	United States	$	12,716	$	12,501
	International		29,413		28,520
Total Exploration and Production			42,129		41,021
Downstream — Refining, Marketing and Transportation
	United States		9,962		9,354
	International		18,998		17,627
Total Refining, Marketing and Transportation			28,960		26,981
Chemicals
	United States		2,226		2,165
	International		664		662
Total Chemicals			2,890		2,827
Total Segment Assets			73,979		70,829
All Other
	United States		7,439		6,644
	International		7,145		3,997
Total All Other			14,584		10,641
Total Assets — United States			32,343		30,664
Total Assets — International			56,220		50,806
Total Assets		$	88,563	$	81,470

     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.

11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Sales from the transfer of products between segments are at prices that approximate market prices. Operating segment sales and other operating revenues, including internal transfers, for the three- and six-month periods ended June 30, 2004 and 2003, are presented in the following table:

Sales and Other Operating Revenues

				Three Months Ended						Six Months Ended
				June 30,						June 30,
				2004			2003			2004			2003
							(Millions of dollars)
Upstream — Exploration and Production
	United States			$	3,773		$	3,564		$	8,009		$	7,228
	International				4,477			3,635			8,486			7,751
		Subtotal			8,250			7,199			16,495			14,979
	Intersegment Elimination — United States				(1,911	)		(1,910	)		(4,363	)		(3,726	)
	Intersegment Elimination — International				(2,725	)		(1,810	)		(4,807	)		(3,913	)
			Total		3,614			3,479			7,325			7,340
Downstream — Refining, Marketing and Transportation
	United States				15,391			12,016			28,816			24,166
	International				17,251			13,209			32,801			27,438
		Subtotal			32,642			25,225			61,617			51,604
	Intersegment Elimination — United States				(63	)		(48	)		(92	)		(88	)
	Intersegment Elimination — International				(2	)		(28	)		(2	)		(33	)
			Total		32,577			25,149			61,523			51,483
Chemicals
	United States				131			114			255			222
	International				211			189			427			388
		Subtotal			342			303			682			610
	Intersegment Elimination — United States				(44	)		(32	)		(83	)		(63	)
	Intersegment Elimination — International				(28	)		(19	)		(54	)		(39	)
			Total		270			252			545			508
All Other
	United States				240			123			449			242
	International				34			25			64			53
		Subtotal			274			148			513			295
	Intersegment Elimination — United States				(110	)		(32	)		(196	)		(60	)
	Intersegment Elimination — International				(1	)		(2	)		(2	)		(2	)
			Total		163			114			315			233
Sales and Other Operating Revenues
	United States				19,535			15,817			37,529			31,858
	International				21,973			17,058			41,778			35,630
		Subtotal			41,508			32,875			79,307			67,488
	Intersegment Elimination — United States				(2,128	)		(2,022	)		(4,734	)		(3,937	)
	Intersegment Elimination — International				(2,756	)		(1,859	)		(4,865	)		(3,987	)
			Total Sales and Other Operating Revenues	$	36,624		$	28,994		$	69,708		$	59,564

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 6. Restructuring and Reorganization Costs

     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 current 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:

	Amount
	(Millions of dollars
	before tax)
Balance at January 1, 2004	$	240
Additions		33
Payments		(115	)
Balance at June 30, 2004	$	158

     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 half of 2004.

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

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

     Throughout 2004 and 2003, ChevronTexaco implemented legal reorganizations in which certain ChevronTexaco subsidiaries transferred assets to or under CUSA and other ChevronTexaco companies were merged with and into CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the table below gives retroactive effect to the reorganizations in a manner similar to a pooling of interests, with all periods presented as if the companies had always been combined and the reorganizations had occurred on January 1, 2003. However, the financial information included below may not reflect the financial position and operating results in the future, or the historical results in the periods presented, had the reorganizations actually occurred on January 1, 2003.

	Six Months Ended
	June 30,
	2004		2003
	(Millions of dollars)
Sales and other operating revenues	$	50,074	$	40,993
Costs and other deductions		46,567		38,642
Income from discontinued operations		81		41
Net income(1)		2,350		1,248

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

13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	At June 30,		At December 31,
	2004		2003
	(Millions of dollars)
Current assets	$	18,816	$	15,539
Other assets(1)		21,194		21,348
Current liabilities		14,446		13,122
Other liabilities		13,592		14,136
Net equity	$	11,972	$	9,629
Memo: Total Debt	$	8,473	$	9,091

(1)  Includes assets held for sale of $1,025 million and $1,052 million at June 30, 2004 and December 31, 2003, respectively.

Note 8. Summarized Financial Data — Chevron Transport Corporation

     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:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2004		2003		2004		2003
	(Millions of dollars)
Sales and other operating revenues	$	142	$	148	$	322	$	373
Costs and other deductions		119		120		242		307
Net income		22		27		75		62

	At June 30,		At December 31,
	2004		2003
	(Millions of dollars)
Current assets	$	248	$	116
Other assets		249		338
Current liabilities		70		96
Other liabilities		295		243
Net equity	$	132	$	115

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

Note 9. Income Taxes

     Taxes on income from continuing operations for the second quarter and first half of 2004 were $2.1 billion and $3.8 billion, respectively, compared with $1.4 billion and $3.1 billion for the comparable periods in 2003. The associated effective tax rates for the 2004 and 2003 second quarters were 33 percent and 46 percent, respectively. For the year-to-date periods, the effective tax rates were 36 percent and 46 percent, respectively.

     The effective tax rate for the three- and six-month periods of 2004 benefited from changes in the income tax laws for certain international operations and the effect of the Canadian capital gains tax rate on the sale of upstream assets in western Canada. In addition, compared with the corresponding periods in 2003, these lower

14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

effective tax rates for both the second quarter and year-to-date periods of 2004 resulted mainly from a change in the mix of international upstream earnings occurring in countries with different tax rates.

Note 10. Stock Options

     At June 30, 2004, the company had stock-based compensation plans. The company accounts for those plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The following table illustrates the effect on net income and earnings per share if the company had applied the fair-value recognition provisions of Financial Accounting Standards Board (FASB) Statement No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2003			2004			2003
	(Millions of dollars)
Net income, as reported	$	4,125		$	1,600		$	6,687		$	3,520
Add: Stock-based employee compensation expense included in reported net income determined under APB No. 25, net of related tax effects		—			—			—			—
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for awards, net of related tax effects		(7	)		(4	)		(13	)		(8	)
Pro forma net income	$	4,118		$	1,596		$	6,674		$	3,512
Net income per share:
Basic — as reported	$	3.88		$	1.51		$	6.29		$	3.32
Basic — pro forma	$	3.88		$	1.51		$	6.28		$	3.31
Diluted — as reported	$	3.88		$	1.50		$	6.28		$	3.31
Diluted — pro forma	$	3.88		$	1.50		$	6.27		$	3.30

Note 11. Employee Benefits

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

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

15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The components of net periodic benefit costs for 2004 and 2003 were:

			Three Months Ended						Six Months Ended
			June 30,						June 30,
			2004			2003			2004			2003
			(Millions of dollars)
Pension Benefits
United States
	Service cost		$	43		$	35		$	85		$	68
	Interest cost			83			84			165			168
	Expected return on plan assets			(90	)		(53	)		(177	)		(109	)
	Amortization of prior-service costs			10			12			21			23
	Recognized actuarial losses			28			35			56			64
	Settlement losses			24			27			44			62
		Total United States		98			140			194			276
International
	Service cost			18			16			35			27
	Interest cost			46			45			89			78
	Expected return on plan assets			(44	)		(43	)		(85	)		(67	)
	Amortization of transitional assets			1			(1	)		1			(2	)
	Amortization of prior-service costs			4			4			8			7
	Recognized actuarial losses			13			12			26			21
	Curtailment losses			2			—			2			—
	Termination benefit recognition			1			—			1			—
		Total International		41			33			77			64
Net Periodic Pension Benefit Costs			$	139		$	173		$	271		$	340
Other Benefits(1)
	Service cost		$	8		$	7		$	16		$	14
	Interest cost			47			48			93			95
	Amortization of prior-service costs			—			—			(1	)		(1	)
	Recognized actuarial losses			5			2			12			5
Net Periodic Other Benefit Costs			$	60		$	57		$	120		$	113

(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.

     At the end of 2003, the company estimated that contributions to employee pension plans during 2004 would total $785 million (composed of $585 million for U.S. plans and $200 million for the international plans). In the second quarter 2004, the company funded $45 million ($12 million and $33 million to the U.S. and international plans, respectively). Through June 30, 2004, a total of $594 million had been contributed ($550 million for the U.S. plans and $44 million for international plans), leaving $191 million to be contributed in the second half 2004 ($35 million for the U.S. and $156 for international).

     The company will conduct additional studies in the second half 2004 to review the full year’s appropriate funding levels, which could change significantly from the original estimates. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors.

     In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became law. The Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy, to sponsors of retiree health care plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure

16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2).

     In June 2004, the company announced changes to its primary U.S. postretirement benefit plan. These changes will become effective as of January 1, 2005, and include limits on future increases to company contributions for retiree medical coverage. In addition, the plan’s prescription drug coverage for retirees will become secondary to Medicare Part D starting in 2006. These combined changes reduced the company’s accumulated postretirement benefit obligation (APBO) as of June 30, 2004, by approximately $663 million, primarily attributable to the change in prescription drug coverage. As a result of these changes, the company estimates other periodic benefit costs for the remainder of 2004 will be $52 million lower than they would have been before the changes were made to the plan. In accordance with FSP FAS 106-2, the APBO reduction does not reflect any provision for the federal subsidy because the plan’s prescription drug benefit (as amended) will not be actuarially equivalent to Medicare Part D.

     The company is reviewing its other U.S. postretirement benefit plans to determine the actuarial equivalency of the plans’ prescription drug benefits and to identify any additional impacts of the Act. The company does not anticipate that the impact will be significant.

     During the second quarter, the company contributed $52 million to its other postretirement benefit plans. For the first half of 2004, the company contributed a total of $102 million.

Note 12. Litigation

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

     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,

17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 butde minimisuse of MTBE in gasoline it manufactures in the United States.

Note 13. Other Contingencies and Commitments

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

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

     Guarantees. The company and its subsidiaries have certain other contingent liabilities with respect to guarantees, direct or indirect, of debt of affiliated companies or others and long-term unconditional purchase obligations and commitments, throughput agreements and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. Under the terms of the guarantee arrangements, generally the company would be required to perform should the affiliated company or third party fail to fulfill its obligations under the arrangements. In some cases, the guarantee arrangements have recourse provisions that would enable the company to recover any payments made under the terms of the guarantees from assets provided as collateral.

     Indemnities. The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell Oil Company (Shell) and Saudi Refining Inc. in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover general contingent liabilities, including those associated with the Unocal patent litigation. The company would be required to perform should the indemnified liabilities become actual losses and could be required to make maximum future payments of $300 million. The company has paid approximately $28 million under these contingencies and has disputed approximately $38 million in claims submitted by Shell under these indemnities. Arbitration of this dispute is scheduled for 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.

18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     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.

     Other Commitments. The company has commitments related to preferred shares of subsidiary companies. Texaco Capital LLC, a wholly owned finance subsidiary, has issued $67 million of Deferred Preferred Shares, Series C (Series C). Dividends amounting to $60 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.

     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 believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemicals concerns.

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

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

19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

presence in those countries. Internal unrest, acts of violence or strained relations between a host government and the company or other governments may affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results, and are carefully considered by management when evaluating the level of current and future activity in such countries.

     Equity Redetermination. For crude oil and natural gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude oil and natural gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for ChevronTexaco’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills in California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. ChevronTexaco currently estimates its maximum possible net before-tax liability at approximately $200 million. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at about $50 million. The timing of the settlement and the exact amount within this range of estimates is uncertain.

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

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

Note 14. New Accounting Standards

     The Securities and Exchange Commission (SEC) has questioned certain public companies in the crude oil and natural gas and mining industries as to the proper accounting for, and reporting of, acquired contractual mineral interests under Financial Accounting Standards Board (FASB) Statement No. 141, “Business Combinations” (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 FASB Staff is addressing this issue with the proposed FASB Staff Position No. FAS 142-b, “Application of FASB Statement No. 142,Goodwill and Other Intangible Assets, to Oil- and Gas- Producing Entities”. 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 finalized.

     For ChevronTexaco, the net book value of this category of mineral interests investment at June 30, 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

20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, beginning on page 15, for discussion related to the company’s implementation of FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.”

Note 15. Cumulative Effect of Changes in Accounting Principles

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

     In the first quarter 2003, the company recorded a net after-tax charge of $200 million for the cumulative effect of the adoption of FAS 143, including the company’s share of amounts attributable to equity affiliates. The cumulative-effect adjustment also increased the following balance sheet categories: “Properties, plant and equipment,” $2.6 billion; “Accrued liabilities,” $115 million; and, “Deferred credits and other noncurrent obligations,” $2.7 billion. “Noncurrent deferred income taxes” decreased by $21 million.

     Upon adoption, no significant asset retirement obligations associated with any legal obligations to retire refining, marketing and transportation (downstream) and chemical long-lived assets generally were recognized, as indeterminate settlement dates for the asset retirements prevented estimation of the fair value of the associated retirement obligation. The company performs periodic reviews of its downstream and chemical long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.

     Also in the first quarter 2003, the company recorded an after-tax gain of $4 million for its share of the Dynegy affiliate’s cumulative effect of adoption of Emerging Issue Task Force Consensus No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” effective January 1, 2003.

Note 16. Subsequent Events

     On July 28, 2004, the company’s Board of Directors approved a two-for-one stock split in the form of a stock dividend to the company’s stockholders of record on August 19, 2004 with distribution of shares on or about September 10, 2004. The total number of authorized common stock shares and associated par value was unchanged by this action. Per share information in the Consolidated Statement of Income (page 3) and stockholders’ equity information in the Consolidated Balance Sheet (page 5) are presented on a pre-split basis.

21

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The following table illustrates the pro forma effect on a post-split basis to the stockholders’ equity accounts as if the effective date of the split had occurred at June 30, 2004 and December 31, 2003.

		At June 30, 2004						At December 31, 2003
		As Presented			Pro Forma			As Presented			Pro Forma
					(Millions of dollars)
Stockholders’ Equity
Preferred stock		$	—		$	—		$	—		$	—
Common stock, at $.75 par value			853			1,706			853			1,706
Capital in excess of par value			4,915			4,062			4,855			4,002
Retained earnings			40,455			40,455			35,315			35,315
Accumulated other comprehensive loss			(820	)		(820	)		(809	)		(809	)
Deferred compensation and benefit plan trust			(576	)		(576	)		(602	)		(602	)
Treasury stock, at cost			(3,801	)		(3,801	)		(3,317	)		(3,317	)
	Total Stockholders’ Equity	$	41,026		$	41,026		$	36,295		$	36,295

     The following table illustrates the pro forma effect on a post-split basis to earnings per share as if the effective date of the split had occurred as of the dates of the financial statements presented below.

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2004		2003		2004		2003
Pro Forma:
Per Share of Common Stock:
	Income From Continuing Operations
		— Basic	$	1.92	$	0.74	$	3.11	$	1.72
		— Diluted	$	1.92	$	0.74	$	3.10	$	1.72
	Income From Discontinued Operations
		— Basic	$	0.02	$	0.01	$	0.04	$	0.02
		— Diluted	$	0.02	$	0.01	$	0.04	$	0.02
	Cumulative Effect of Changes in Accounting Principles
		— Basic		—		—		—	$	(0.09	)
		— Diluted		—		—		—	$	(0.09	)
	Net Income
		— Basic	$	1.94	$	0.75	$	3.15	$	1.65
		— Diluted	$	1.94	$	0.75	$	3.14	$	1.65
	Weighted Average Number of Shares Outstanding (000s)
		— Basic		2,122,794		2,124,512		2,124,805		2,124,274
		— Diluted		2,129,391		2,127,418		2,130,876		2,127,309

22

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

Second Quarter 2004 Compared with Second Quarter 2003

and First Half 2004 Compared with First Half 2003

Key Financial Results

Income From Continuing Operations by Major Operating Area

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2004		2003			2004			2003
		(Millions of dollars)
Income from Continuing Operations
Upstream — Exploration and Production
	United States	$	912	$	638		$	1,734		$	1,633
	International		2,028		624			3,153			1,581
Total Exploration and Production			2,940		1,262			4,887			3,214
Downstream — Refining, Marketing and Transportation
	United States		517		187			793			257
	International		527		251			891			496
Total Refining, Marketing and Transportation			1,044		438			1,684			753
Chemicals			59		34			133			37
All Other			39		(154	)		(98	)		(329	)
Income From Continuing Operations			4,082		1,580			6,606			3,675
Income From Discontinued Operations — Upstream			43		20			81			41
Income Before Cumulative Effect of Changes in Accounting Principles(1)(2)			4,125		1,600			6,687			3,716
Cumulative Effect of Changes in Accounting Principles			—		—			—			(196	)
Net Income(1)(2)		$	4,125	$	1,600		$	6,687		$	3,520

(1) Includes foreign currency effects		$	45	$	(157	)	$	2	$	(202	)
(2) Includes special gains (charges):
	Continuing Operations	$	585	$	(104	)	$	530	$	(143	)
	Discontinued Operations		—		(13	)		—		(13	)
	Total	$	585	$	(117	)	$	530	$	(156	)

     Net incomefor the second quarter 2004 was $4.1 billion ($3.88 per share — diluted). The amount included a special-item gain of $585 million ($0.55 per share — diluted) related to the sale of upstream assets in western Canada and a one-time benefit of $255 million ($0.24 per share — diluted) associated with changes in income tax laws for certain international operations. Also included was income of $43 million ($0.04 per share — diluted) relating to certain assets that were classified as discontinued operations because of their pending sale. Accounting for discontinued operations is discussed in Note 3 beginning on page 7.

     Net income for the 2003 second quarter was $1.6 billion (1.50 per share — diluted), which included net special charges of $117 million ($0.11 per share — diluted), mainly for the write-down of assets in anticipation of sale. Also included was income of $20 million ($0.02 per share — diluted) for discontinued operations.

23

     First-half 2004 net income was $6.7 billion ($6.28 per share — diluted). Besides the second quarter items mentioned above, the first half included a special-item charge of $55 million ($0.05 per share — diluted) for an adverse litigation ruling. Income from discontinued operations was $81 million ($0.08 per share diluted) for the first half of 2004.

     For the first six months of 2003, net income was $3.5 billion ($3.31 per share — diluted). Besides the second quarter items, results also included a charge of $196 million ($0.18 per share — diluted) for the cumulative effect of changes in accounting principles, and a charge of $39 million ($0.04 per share — diluted) for the company’s share of losses from asset sales by an equity affiliate. Income from discontinued operations was $41 million for the first half of 2003 ($0.04 per share — diluted). The cumulative effect of changes in accounting principles is discussed in Note 15 on page 21.

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

     Upstream earningsfrom continuing operations in the second quarter 2004 were $2.9 billion, up from $1.3 billion a year earlier, as the segment benefited mainly from higher prices for crude oil and natural gas, the gain on the sale of assets in western Canada and a $208 million one-time benefit from changes in the income tax laws for certain international operations. For the six-month period, upstream earnings increased $1.7 billion.

     In the second quarter 2004, the company’s average price for U.S. crude oil and natural gas liquids increased nearly 30 percent from the year-ago period to more than $32 per barrel. For the first half of 2004, average prices for U.S. crude oil and natural gas liquids increased about 16 percent from the year-earlier period to more than $31 per barrel. Internationally, the average liquids price increased 35 percent to approximately $32 per barrel between quarters and increased 15 percent to $31 per barrel between the comparative six-month periods.

     The average U.S. natural gas sales price in the second quarter 2004 increased 9 percent from the 2003 quarter to $5.59 per thousand cubic feet. Internationally, the average natural gas price decreased about 4 percent to $2.55 per thousand cubic feet. For the first six-month periods, the average U.S. natural gas sales price decreased about 2 percent to $5.40 per thousand cubic feet, while average international prices were marginally lower.

     Worldwide net oil-equivalent production in 2004, including volumes produced from oil sands and production under an operating service agreement, declined approximately 4 percent and 3 percent from the comparable second quarter and six-month periods of 2003, respectively. About one-half of the decline in both periods was associated with property sales in 2003.

     Refer to pages 28-29 for a further discussion of upstream results in 2004 and 2003.

     Downstream earningswere $1 billion and $1.7 billion in the second quarter and six months of 2004, respectively, up $0.6 billion and $0.9 billion from the comparable periods in 2003. Earnings in 2004 benefited mainly from higher average industry margins for refined products, which resulted mainly from higher demand in most of the areas in which the company operates. Refer to pages 29-30 for a further discussion of downstream results in 2004 and 2003.

Business Environment and Outlook

     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

24

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 six months of 2004 and remained at higher levels than the corresponding period in 2003. For the first six months of 2004, the average spot price for WTI was slightly below $37 per barrel, compared with about $32 per barrel in the year-ago period. These relatively high industry prices reflected increased demand from higher economic growth in Asia and the United States, the heightened level of geopolitical uncertainty across the globe, and supply concerns in the Middle East and other key producing regions.

     U.S. Benchmark prices for Henry Hub natural gas averaged nearly $5.50 per thousand cubic feet for the year 2003. In the first six months of 2004, the U.S. benchmark natural gas price averaged over $5.80 per thousand cubic feet, compared to over $6.20 per thousand cubic feet in the first half of 2003. Natural gas prices were higher in the first half 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 34 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 six 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 3 percent from

25

the year-ago period. The decrease was largely the result of lower production in the United States due to normal field declines and the result of property sales. International oil-equivalent production increased about 1 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 in the first half of 2004, including net barrels from oil sands and production under an operating service agreement, was in the OPEC-member countries of Indonesia, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. Although the company’s production levels during the first six months of 2004 were not constrained in these areas 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 properties. The company has begun initial production-resumption efforts in certain areas. While production in 2004 was not constrained in Nigeria through early August, 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 second quarter and first six months of 2004 primarily from improved demand and higher average refined product margins for the industry in most of the company’s operating areas. Industry margins may be volatile in the future, depending primarily on price movements for crude oil feedstocks, demand for product, inventory levels, refinery maintenance and mishaps, and other factors.

     Chemicals. Earnings of $59 million in the second quarter 2004 were up from the year-ago period. Six-month profits of $133 million increased $96 million from the previous year. Earnings for the company’s Oronite subsidiary improved on higher margins for lubricant additives in both periods. Earnings for the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate rose as the result of increased commodity chemical product sales volumes and higher affiliate income compared with the 2003 periods.

Operating Developments

     Operating developments and events in recent months included:

Upstream

•  North America —The company announced the sale of approximately 150 onshore producing properties in the United States for $1.1 billion. This transaction is expected to close in the third quarter 2004. In June, the company completed the sale of its western Canada crude oil and natural gas producing assets. The sale of a Canadian natural-gas processing business was finalized in July. Combined proceeds from the Canadian asset sales were approximately $1 billion. These divestments were part of plans announced in 2003 to dispose of assets that did not provide sufficient long-term value and to improve the overall competitive performance and operating efficiency of the company’s exploration and production portfolio.

26

•  Angola —The Angolan government awarded the company an extension from 2010 to 2030 of the Block 0 operating concession. The extension agreement formalizes an earlier preliminary agreement governing major Block 0 capital investments, including the Sanha Condensate Project that is being designed to help eliminate gas flaring during the production of crude oil. ChevronTexaco is the operator of the Block 0 concession and holds an approximate 39 percent interest.

•  Kazakhstan —First crude oil from the Karachaganak Field in Kazakhstan was loaded at Russia’s Black Sea port of Novorossiysk in June. This represented the first shipment of Karachaganak crude oil through the Caspian Pipeline Consortium export pipeline that provides access to world markets.

•  Democratic Republic of Congo —In July, ChevronTexaco completed the sale of its wholly owned subsidiary, Muanda International Oil Company (MIOC), in the Democratic Republic of Congo (DRC). MIOC holds a 50 percent interest in, and is operator of, the DRC’s 390-square-mile (1,010-square-kilometer) offshore concession.

•  Thailand —The company announced successful exploration and appraisal drilling results in Block G4/43, located in the Gulf of Thailand, in July. Block G4/43 is adjacent to the company’s Chevron Offshore (Thailand) Ltd.’s Block B8/32, where the company is the operator and holds a 51.7 percent interest.

•  Global Natural Gas Projects —In Australia, the North West Shelf Venture began commissioning of a fourth LNG train, which is expected to produce first LNG in September. This will boost the venture’s LNG production by more than 50 percent. ChevronTexaco holds a one-sixth interest in the joint venture.

Downstream

•  Singapore —The company acquired an additional interest in the Singapore Refining Company Pte. Ltd. (SRC), increasing ownership from 33 percent to 50 percent. This 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 investments in approximately 1,500 service station sites, with dispositions totaling more than 800 sites from the program’s inception in 2003 through the second quarter of 2004.

•  United States Marketing —The company resumed marketing gasoline under the Texaco retail brand in the United States and plans to supply more than 1,000 Texaco retail sites in southern and eastern states by the end of 2004. Additionally, ChevronTexaco became the first United States gasoline marketer to meet new performance criteria for top-tier detergent gasoline that were set by four of the world’s largest automobile manufacturers.

Chemicals

•  Saudi Arabia —Project approval was obtained by the company’s 50 percent-owned affiliate, Chevron Phillips Chemical Company LLC, for the construction of an integrated styrene facility and the expansion of an adjacent aromatics plant at Al Jubail, Saudi Arabia. Engineering, procurement and construction contracts for the project were also awarded. Start-up activities are scheduled to begin in 2007.

Other

•  Common Stock Dividend and Stock Repurchase Program —In late July, the company announced an increase of nearly 10 percent in its quarterly common stock dividend, which was immediately followed by a 2-for-1 stock split in the form of a stock dividend. In connection with a targeted $5 billion stock repurchase program initiated April 1, 2004, the company purchased 7,700,000 shares in the open market for $707 million through the end of July. The repurchase program is in effect for a period up to three years from the April 2004 start-up.

27

Results of Operations

     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 beginning on page 9 related to a discussion of the company’s “reportable segments,” as defined in FAS 131, “Disclosures about Segments of an Enterprise and Related Information.”) To aid in the understanding of changes in segment income between periods, the discussion, when applicable, may be in two parts — first on underlying trends, and second on special 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. Upstream — Exploration and Production

			Three Months Ended					Six Months Ended
			June 30,					June 30,
			2004		2003			2004			2003
			(Millions of dollars)
	Income From Continuing Operations(1)		$	912	$	638		$	1,734		$	1,633
	Income From Discontinued Operations(1)			43		20			81			41
	Cumulative Effect of Accounting Change			—		—			—			(350	)
	Segment Income(1)		$	955	$	658		$	1,815		$	1,324
(1) Includes special charges:
		Continuing Operations	$	—	$	(45	)	$	(55	)	$	(45	)
		Discontinued Operations		—		(13	)		—			(13	)
		Total	$	—	$	(58	)	$	(55	)	$	(58	)

     U.S. exploration and production income from continuing operations was $912 million in the second quarter, up $274 million from the 2003 period. For the six-month period, income from continuing operations was $1.7 billion, about $100 million higher than a year earlier. The large improvement in second quarter 2004 earnings was primarily from higher prices for crude oil and natural gas. Prices were also somewhat higher for the comparative six-month periods and earnings also improved on gains from property sales.

     Partially offsetting the benefit of higher prices in the quarter was the effect of an 8 percent decline in oil-equivalent production to 869,000 barrels per day (excluding property sales, the decline was 6 percent between periods). For the six-month period in 2004, the benefit of higher prices was partially offset by a 9 percent decline in net oil-equivalent production to 872,000 barrels per day (excluding property sales, the decline was 8 percent). Besides the effect of property sales, normal field declines also contributed to the lower production in both periods, the effects of which were only partially offset by increased and first-time production in various fields.

     The average liquids realization for the second quarter was $32.68 per barrel, an increase of nearly 30 percent from $25.25 per barrel in the year-ago period. For the comparative six-month periods, the average liquids realization of $31.45 per barrel was up 16 percent from $27.20 per barrel. The average natural gas realization for the second quarter 2004 was $5.59 per thousand cubic feet, compared with $5.11 in the 2003 quarter. Year-to-date, the average natural gas realization was $5.40 per thousand feet, compared with $5.49 in 2003.

     The net liquids component of oil-equivalent production was down 5 percent to 535,000 barrels per day for the quarter and down 6 percent to 534,000 barrels per day for the six-month period. Net natural gas production averaged 2 billion cubic feet per day, down approximately 13 percent from the year-ago quarter and six-month period.

28

     The six-month 2004 results include a special charge of $55 million due to an adverse litigation matter. Included in the six-month 2003 results were net special charges of $58 million, mainly for the write-down of assets in anticipation of sale.

International Upstream — Exploration and Production

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2004		2003			2004		2003
		(Millions of dollars)
	Income Before Cumulative Effect of Change in Accounting Principle(1)(2)	$	2,028	$	624		$	3,153	$	1,581
	Cumulative Effect of Accounting Change		—		—			—		145
	Segment Income(1)(2)	$	2,028	$	624		$	3,153	$	1,726
(1) Includes foreign currency effects		$	22	$	(117	)	$	2	$	(163	)
(2) Includes special gains (charges)			585		(13	)		585		(13	)

     International exploration and production segment income increased $1.4 billion from the year-ago quarter to $2 billion, due primarily to higher average prices for crude oil, a $585 million special gain from the sale of producing properties in western Canada and a one-time benefit of $208 million related to changes in certain income-tax laws. Net foreign exchange effects increased earnings $22 million in the 2004 quarter, primarily from the strengthening of the U.S. dollar against the currencies of Canada and the United Kingdom. First-half 2004 earnings increased $1.6 billion from the year-ago period due primarily to the same factors as for the change in quarterly profits. Lower exploration expenses also contributed to the improvement.

     The average liquids realization for the second quarter 2004 was $32.48 per barrel, an increase of nearly 35 percent from last year’s quarter. For the first half of 2004, average liquids realization was $30.90 per barrel compared with $26.81 per barrel in the year-ago period. The average natural gas realization for the second quarter 2004 was $2.55 per thousand cubic feet, compared with $2.66 in the 2003 quarter. For the first six-months of 2004, average natural gas realization was $2.61 per thousand cubic feet, about 2 percent lower than the comparable year-ago period. This price movement was mainly associated with less production in 2004 in areas of higher prices.

     Net oil-equivalent production for the second quarter 2004 — including other produced volumes of 142,000 net barrels per day from oil sands and production under an operating service agreement — decreased 1 percent, or 22,000 barrels per day, from the 2003 quarter. Excluding the effect of property sales, oil-equivalent production increased marginally, as new liquids production in Chad was partially offset by the effect of lower cost-oil recovery volumes under production-sharing terms in Indonesia. The net liquids component of oil-equivalent production decreased 24,000 barrels per day to 1,356,000, while natural gas production was up slightly to 2.1 billion cubic feet per day. For the first-half 2004, net oil-equivalent production — including other produced volumes of 141,000 net barrels per day from oil sands and production under an operating service agreement — increased about 1 percent. Excluding the effect of property sales, net oil-equivalent production increased approximately 2 percent. Net liquids production increased 9,000 barrels per day to 1,360,000 barrels per day between the six-month periods. Net natural gas production was up marginally.

U.S. Downstream — Refining, Marketing and Transportation

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2004		2003		2004		2003
	(Millions of dollars)
Segment Income	$	517	$	187	$	793	$	257

     U.S. downstream earnings of $517 million improved $330 million from the 2003 quarter. For the first half of 2004, earnings were $793 million, versus $257 million in the corresponding 2003 period. Both periods

29

benefited from improved industry margins for refined products and higher production at the company’s Pascagoula, Mississippi, refinery, which was undergoing modifications for “clean-fuels” manufacturing during the second quarter 2003. The improved margins were driven by increased demand in an improved economy.

     The second quarter 2004 average refined-product sales price increased nearly 34 percent to $50.79 per barrel, compared with the year-ago quarter. For the six-month periods, the average refined product sales price of $48.02 in 2004 was up 17 percent from $40.88 per barrel in 2003. Refined-product sales volumes increased about 6 percent to 1,551,000 barrels per day in the second quarter, and were about 8 percent higher in the six-month period at 1,506,000 barrels per day. The increase between periods was primarily from higher sales of unbranded gasoline, diesel fuel and fuel oil. Branded gasoline sales volumes were essentially unchanged from the year-ago quarter at 554,000 barrels per day. For the six months, branded gasoline sales volumes were 553,000 barrels per day, marginally lower than the comparative 2003 period.

International Downstream — Refining, Marketing and Transportation

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2004		2003			2004		2003
		(Millions of dollars)
	Segment Income(1)(2)	$	527	$	251		$	891	$	496
(1) Includes foreign currency effects		$	27	$	(60	)	$	2	$	(78	)
(2) Includes net special charges			—		(46	)		—		(85	)

     International refining, marketing and transportation segment income increased $276 million in the 2004 second quarter. Earnings were $395 million higher in the first half of 2004 than the year-ago period. The improvement resulted primarily from higher average refined-product margins, improved earnings from equity affiliates and a $47 million one-time benefit from changes in certain income-tax laws. Foreign currency effects increased earnings $27 million in the current quarter.

     Total refined-product sales volumes of approximately 2,456,000 barrels per day were nearly 7 percent higher in the 2004 quarter. For the six months, refined-product sales volumes of 2,413,000 barrels per day in 2004 were 4 percent higher than in the corresponding 2003 period. This improvement for both periods represented higher sales of unbranded gasoline and jet fuel.

     Included in the second quarter 2003 results was a special charge of $46 million for the impairment of assets in anticipation of sale. In addition to the second quarter item, the six-month 2003 results included an additional special charge of $39 million for the company’s share of losses from asset sales by an equity affiliate.

Chemicals

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2004			2003		2004			2003
		(Millions of dollars)
	Segment Income(1)	$	59		$	34	$	133		$	37
(1) Includes foreign currency effects		$	(2	)	$	7	$	(4	)	$	10

     Chemical operations earned $59 million in the second quarter of 2004, compared with $34 million in the 2003 quarter. For the six-month periods, earnings increased $96 million. Earnings for the company’s Oronite subsidiary improved on higher margins for lubricant additives in both periods. Earnings for the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate rose as the result of increased commodity chemical product sales volumes and higher equity-affiliate income compared with the 2003 periods.

30

All Other

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2004			2003			2004			2003
		(Millions of dollars)
	Net Income (Charges) Before Cumulative Effect of Change in Accounting Principles	$	39		$	(154	)	$	(98	)	$	(329	)
	Cumulative Effect of Accounting Change		—			—			—			9
	Net Segment Income (Charges)(1)	$	39		$	(154	)	$	(98	)	$	(320	)
(1) Includes foreign currency effects		$	(2	)	$	13		$	2		$	29

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

     Net segment income before the cumulative effect of changes in accounting principles were $39 million in the second quarter of 2004, compared with net charges of $154 million in the corresponding 2003 period. The current quarter’s results benefited from higher earnings from the company’s worldwide power business and the sale of the company’s gasification technology business. In addition to the current quarter benefits, this year’s results improved from higher earnings from the company’s investment in Dynegy and lower net interest expense.

     For further information related to the company’s investment in Dynegy, please see “Information Relating to the Company’s Investment in Dynegy” beginning on page 32.

                  Consolidated Statement of Income

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

     Sales and other operating revenuesfor the second quarter 2004 were $36.6 billion, up from $29 billion in last year’s quarter. For the first six months of 2004, sales and operating revenues were $69.7 billion, up from $59.6 billion in the 2003 period. Revenues increased mainly from higher prices for crude oil and refined products worldwide.

     Income from equity affiliatesincreased $525 million to $740 million in the second quarter 2004. For the six-month period, income from equity affiliates increased approximately $700 million to $1.2 billion. The increases were primarily the result of improved earnings from CPChem, Caspian Pipeline, Dynegy, Tengizchevroil and downstream affiliates in the Asia-Pacific area. The second quarter 2003 included special charges of $46 million related to write-downs due to anticipated asset dispositions. For the 2003 six-month period, special charges were $85 million and included a loss from asset sales and the impairment of an investment in an equity affiliate.

     Other incomeof $937 million was up from $62 million in the 2003 second quarter. For the six-month periods, other income was $1.1 billion, compared to $109 million last year. The improvement in both periods of 2004 occurred primarily from higher net gains from asset sales, including the gain of $713 million related to the sale of upstream assets in western Canada.

     Purchased crude oil and productscosts of $22.5 billion in the second quarter 2004 were up from $17.3 billion in the 2003 quarter. For the six-month period, such costs were $42.6 billion, up from $35.5 billion in the year-ago period. The increases between periods were primarily the result of higher prices and increased purchases of crude oil.

     Operating, selling, general and administrative expensesof $3.2 billion in the second quarter 2004 were up from $2.9 billion in the year-ago quarter. For the six-month periods, such expenses were $6.4 billion, compared to $6 billion last year. For the quarter and six-month periods, the increases included higher

31

operating expenses for new production and transportation activities in Chad/ Cameroon, and increased expenses for tanker charters.

     Exploration expenseswere $164 million in the second quarter 2004, compared with $147 million in the second quarter 2003. Amounts were higher in the current quarter, primarily from higher international seismic expenses. For the six month periods, exploration expenses decreased about $50 million, primarily from lower amounts for well write-offs.

     Depreciation, depletion and amortizationexpenses were $1.3 billion in the second quarter 2004, compared with $1.4 billion in the second quarter 2003. For the six-month periods, expenses were $2.5 billion and $2.6 billion in 2004 and 2003, respectively. The 2003 quarter and six months included special charges of $102 million for the write-down of assets in anticipation of sale.

     Taxes other than on incomewere $4.9 billion and $4.5 billion in the second quarter of 2004 and 2003, respectively. For the six-month periods, expenses were $9.6 billion and $8.8 billion in 2004 and 2003, respectively. The increase in 2004 primarily reflected the weakened U.S. dollar effect on foreign-currency denominated duties in the company’s European downstream operations.

     Interest and debt expensedecreased $25 million to $93 million in the 2004 second quarter. These expenses decreased $61 million to $187 million in the first six months of 2004. For both periods, the decrease resulted primarily from lower average debt balances.

     Income tax expenserelated to continuing operations for the second quarter and first half of 2004 was $2.1 billion and $3.8 billion, respectively, compared with $1.4 billion and $3.1 billion for the comparable periods in 2003. The associated effective tax rates for the 2004 and 2003 second quarters were 33 percent and 46 percent, respectively. For the year-to-date periods, the effective tax rates were 36 percent and 46 percent, respectively.

     The effective tax rate for the three- and six-month periods of 2004 benefited from changes in income tax laws in certain international operations and the effect of the Canadian capital gains tax rate on the sale of upstream assets in western Canada. In addition, compared with the corresponding periods in 2003, these lower effective tax rates for both the second quarter and year-to-date periods of 2004 resulted mainly from a change in the mix of international upstream earnings occurring in countries with different tax rates.

Information Relating to the Company’s Investment in Dynegy

     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 June 30, 2004, the carrying value of the company’s investment in Dynegy common stock was approximately $150 million. This amount was about $400 million below the company’s proportionate interest in Dynegy’s underlying net assets. This difference resulted from write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value that were deemed to be other than temporary. The approximate $400 million difference has been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors giving rise to the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly to recognize a portion of the difference between these allocated values and Dynegy’s historical book values.

     Investment in Dynegy Notes and Preferred Stock. The face values of the company’s investments in the Junior Notes and Series C shares at June 30, 2004, were $207 million and $400 million, respectively. The estimated fair values of these instruments at that time totaled $539 million, an increase of $9 million from December 31, 2003, after repayments of $18 million of the Junior Notes through June 2004. 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

32

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 July 2004, the company received a payment of approximately $72 million representing principal and interest on the Junior Notes due 2016.

     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 transaction 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 $207 million face value notes.

33

Selected Operating Data

     The following table presents a comparison of selected operating data:

Selected Operating Data(1)(2)

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2004		2003		2004		2003
U.S. Upstream
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			535		563		534		570
	Net Natural Gas Production (MMCFPD)(3)			2,001		2,302		2,031		2,333
	Net Oil-Equivalent Production (MBOEPD)			869		947		872		959
	Sales of Natural Gas (MMCFPD)			3,881		3,987		3,950		4,000
	Sales of Natural Gas Liquids (MBPD)(4)			177		161		180		216
	Revenue from Net Production
		Liquids ($/Bbl.)	$	32.68	$	25.25	$	31.45	$	27.20
		Natural Gas ($/MCF)	$	5.59	$	5.11	$	5.40	$	5.49
International Upstream
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			1,214		1,266		1,219		1,256
	Net Natural Gas Production (MMCFPD)(3)			2,098		2,089		2,134		2,115
	Net Oil-Equivalent Production (MBOEPD)(5)			1,706		1,728		1,716		1,703
	Sales of Natural Gas (MMCFPD)			1,850		2,051		1,894		2,155
	Sales of Natural Gas Liquids (MBPD)			113		103		105		113
	Revenue from Liftings
		Liquids ($/Bbl.)	$	32.48	$	24.10	$	30.90	$	26.81
		Natural Gas ($/MCF)	$	2.55	$	2.66	$	2.61	$	2.65
U.S. and International Upstream
	Total Net Oil-Equivalent Production including Other Produced Volumes (MBOEPD)(3)(5)			2,575		2,675		2,588		2,662
U.S. Refining, Marketing and Transportation
	Sales of Gasoline (MBPD)(4)(6)			685		683		693		652
	Sales of Other Refined Products (MBPD)(4)			866		784		813		745
	Refinery Input (MBPD)			969		985		945		910
	Average Refined Product Sales Price ($/Bbl.)		$	50.79	$	37.87	$	48.02	$	40.88
International Refining, Marketing and Transportation
	Sales of Gasoline (MBPD)(4)(6)			644		539		608		540
	Sales of Other Refined Products (MBPD)			1,278		1,257		1,260		1,250
	Affiliate Sales (MBPD)			534		503		545		524
	Refinery Input (MBPD)(4)			1,063		1,114		1,060		1,099
	Average Refined Product Sales Price ($/Bbl.)		$	54.81	$	44.68	$	53.20	$	46.41

(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	78	51	59
	International	270	256	276	263
(4)	2003 volumes conformed to 2004 presentation.
(5)	Includes other produced volumes (MBPD):
	Athabasca oil sands — net	28	12	28	6
	Boscan Operating Service Agreement	114	102	113	89
		142	114	141	95
(6)	Includes branded and unbranded gasoline.

34

     Liquidity and Capital Resources

     Cash and cash equivalents and marketable securitiestotaled $9.3 billion at June 30, 2004, up from $5.3 billion at year-end 2003. Cash provided by operating activities was approximately $7.9 billion in the first six months of 2004 and was net of $594 million contributed to certain of the company’s pension plans during the period. Cash provided by operating activities in the first half 2003 was $7.1 billion and was net of $57 million for pension plan contributions. Operating activities in the first six months of 2004 generated sufficient funds for the company’s capital and exploratory program and for the payment of dividends to stockholders.

     Dividends. During the first six months of 2004, the company paid dividends of $1.5 billion to common stockholders. Refer to Note 16 on page 21 for information related to the company’s 2-for-1 stock split announced in July 2004 and page 27 for additional information on the company’s quarterly stock dividend increase.

     Debt and Capital Lease Obligations. ChevronTexaco’s total debt and capital lease obligations were $12.1 billion at June 30, 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 $6.1 billion at June 30, 2004, essentially unchanged from $6 billion at December 31, 2003. Of these amounts, $4.3 billion was reclassified to long-term at June 30, 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 second 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 June 30, 2004. In addition, the company had three existing effective “shelf” registrations on file with the SEC that together would permit additional registered debt offerings up to an aggregate $3.8 billion of debt securities.

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

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

     The company’s future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. Further reductions from debt balances at June 30, 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 1.4 at June 30, 2004, compared with 1.2 at December 31, 2003. The current ratio was adversely affected at the end of 2003 and the second quarter 2004 because the company’s inventories are valued on a LIFO basis. At year-end 2003

35

inventories were lower than replacement costs, based on average acquisition costs during the year, by nearly $2.1 billion. The company does not consider its inventory valuation methodology to affect liquidity.

     Debt Ratio — total debt divided by total debt plus equity. This ratio was approximately 23 percent at June 30, 2004, compared with 26 percent at year-end 2003 and 28 percent at June 30, 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. Through July 2004, the company had repurchased 7.7 million shares of common stock at a total cost of $707 million. Through the end of June, $600 million had been repurchased. For additional information, see Part II, Item 2 on page 42.

     Other Commitments. The company has commitments related to preferred shares of subsidiary companies. Texaco Capital LLC, a wholly owned finance subsidiary, has issued $67 million of Deferred Preferred Shares, Series C (Series C). Dividends amounting to $60 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.

     Pension Obligations. At the end of 2003, the company estimated that contributions to employee pension plans during 2004 would total $785 million (composed of $585 million for U.S. plans and $200 million for the international plans). In the second quarter 2004, the company funded $45 million ($12 million and $33 million to the U.S. and international plans, respectively). Through June 30, 2004, a total of $594 million had been contributed ($550 million for the U.S. plans and $44 million for international plans), leaving $191 million to be contributed in the second half 2004 ($35 million for the U.S. and $156 for international).

     The company will conduct additional studies in the second half 2004 to review the full year’s appropriate funding levels, which could change significantly from the original estimates. 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 $3.8 billion in the first six months of 2004, compared with $3.5 billion in the corresponding 2003 period. The amounts included the company’s share of affiliate expenditures of about $600 million and $400 million in the 2004 and 2003 periods, respectively. Expenditures for international exploration and production projects were about $2 billion — about 54 percent of the total expenditures — reflecting the company’s continued emphasis on increasing international upstream activities. The increase from 2003 included nearly $270 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.

36

Capital and Exploratory Expenditures by Major Operating Area

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2004		2003		2004		2003
			(Millions of dollars)
United States
	Upstream — Exploration and Production		$	472	$	391	$	896	$	738
	Downstream — Refining, Marketing and Transportation			86		107		139		227
	Chemicals			34		27		61		44
	All Other			103		87		310		156
		Total United States		695		612		1,406		1,165
International
	Upstream — Exploration and Production			1,151		1,145		2,028		1,990
	Downstream — Refining, Marketing and Transportation			221		147		311		283
	Chemicals			6		5		8		9
	All Other			—		4		2		7
		Total International		1,378		1,301		2,349		2,289
		Worldwide	$	2,073	$	1,913	$	3,755	$	3,454

Contingencies and Significant Litigation

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

     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

37

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 butde minimisuse of MTBE in gasoline it manufactures in the United States.

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

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

     Guarantees. The company and its subsidiaries have certain other contingent liabilities with respect to guarantees, direct or indirect, of debt of affiliated companies or others and long-term unconditional purchase obligations and commitments, throughput agreements and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. Under the terms of the guarantee arrangements, generally the company would be required to perform should the affiliated company or third party fail to fulfill its obligations under the arrangements. In some cases, the guarantee arrangements have recourse provisions that would enable the company to recover any payments made under the terms of the guarantees from assets provided as collateral.

     Indemnities. The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell Oil Company (Shell) and Saudi Refining Inc. in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover general contingent liabilities, including those associated with the Unocal patent litigation. The company would be required to perform should the indemnified liabilities become actual losses and could be required to make maximum future payments of $300 million. The company has paid approximately $28 million under these contingencies and has disputed approximately $38 million in claims submitted by Shell under these indemnities. Arbitration of this dispute is scheduled for 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

38

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.

     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 believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemicals concerns.

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

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

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

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

39

     Equity Redetermination. For crude oil and natural gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude oil and natural gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for ChevronTexaco’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills in California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. ChevronTexaco currently estimates its maximum possible net before-tax liability at approximately $200 million. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at about $50 million. The timing of the settlement and the exact amount within this range of estimates is uncertain.

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

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

New Accounting Standards

     The Securities and Exchange Commission (SEC) has questioned certain public companies in the crude oil and natural gas and mining industries as to the proper accounting for, and reporting of, acquired contractual mineral interests under Financial Accounting Standards Board (FASB) Statement No. 141, “Business Combinations” (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 FASB Staff is addressing this issue with the proposed FASB Staff Position No. FAS 142-b, “Application of FASB Statement No. 142,Goodwill and Other Intangible Assets, to Oil- and Gas- Producing Entities”. 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 finalized.

     For ChevronTexaco, the net book value of this category of mineral interests investment at June 30, 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.

40

     Refer to Note 11 beginning on page 15 for discussion related to the company’s implementation of FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.”

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

Item 4. Controls and Procedures

     (a) Evaluation of disclosure controls and procedures

     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 June 30, 2004, have concluded that as of June 30, 2004, the company’s disclosure controls and procedures were adequate and designed to ensure that material information relating to the company and its consolidated subsidiaries required to be included in the company’s periodic filings under the Exchange Act would be made known to them by others within those entities.

     (b) Changes in internal control over financial reporting

     During the quarter ended June 30, 2004, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.

41

PART II

OTHER INFORMATION

Item 1. Legal Proceedings

     No items.

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

CHEVRONTEXACO CORPORATION

ISSUER PURCHASES OF EQUITY SECURITIES

							Maximum
					Total Number of		Number of Shares
	Total Number		Average		Shares Purchased as		that May Yet Be
	of Shares		Price Paid		Part of Publicly		Purchased Under
Period	Purchased(1)		per Share		Announced Program		the Program
Apr 1-Apr 30, 2004		1,518,731		90.88		1,200,000		—
May 1-May 31, 2004		3,169,423		91.66		3,045,000		—
Jun 1-Jun 30, 2004		2,585,818		92.54		2,298,574		—
Total		7,273,972		91.81		6,543,574		(2)

(1)

Includes 35,737 common shares repurchased through June 30, 2004 of 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. Additionally, includes 694,661 shares delivered or attested to in satisfaction of the exercise price by holders of certain former Texaco Inc. employee stock options exercised during the three-month period ended June 30, 2004.

(2)

On March 31, 2004, the company announced a common stock repurchase program. Acquisitions of up to $5 billion will be made from time to time at prevailing prices as permitted by securities laws and other requirements, and subject to market conditions and other factors. The program will occur over a period of up to three years and may be discontinued at any time. Through June 30, 2004, $600 million has been expended to repurchase 6,543,574 shares since the common stock repurchase program began.

Item 5. Other Information

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

     No change.

42

Item 6. Exhibits and Reports on Form 8-K

     (a) Exhibits

(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

     (b) Reports on Form 8-K

     (1) On July 29, 2004, ChevronTexaco furnished a copy of a press release announcing an increased cash dividend and a two-for-one stock split of the company’s common stock on a Form 8-K dated July 29, 2004.

     (2) On July 30, 2004, ChevronTexaco furnished a copy of a press release announcing unaudited second quarter 2004 net income of $4.125 billion on a Form 8-K dated July 30, 2004.

43

SIGNATURE

     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)

Date: August 4, 2004

44

EXHIBIT INDEX

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

45