Form 10-K -CHEVRONTEXACO CORPORATION

10-K405 1 f80065e10-k405.htm FORM 10-K405 Form 10-K -CHEVRONTEXACO CORPORATION - 12/31/2001

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2001

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-368-2

ChevronTexaco Corporation

(Exact name of registrant as specified in its charter)


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

Registrant’s telephone number, including area code (415) 894-7700

NONE

(Former name or former address, if changed since last report.)

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class		Name of Each Exchange on Which Registered

Common stock par value $.75 per share		New York Stock Exchange, Inc.
Preferred stock purchase rights		Pacific Exchange

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Aggregate market value of the voting stock held by nonaffiliates of the Registrant

As of February 28, 2002 – $89,318,940,000

Number of Shares of Common Stock outstanding as of February 28, 2002 – 1,067,200,937

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2002 Annual Meeting and 2002 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, as amended, in connection with the company’s 2002 Annual Meeting of Stockholders (in Part III)

TABLE OF CONTENTS


PART I
	Item 1. Business
	Item 2. Properties
	Item 3. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
PART II
	Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters
	Item 6. Selected Financial Data
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 7A. Quantitative and Qualitative Disclosures About Market Risk
	Item 8. Financial Statements and Supplementary Data
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
PART III
	Item 10. Directors and Executive Officers of the Registrant
	Item 11. Executive Compensation
	Item 12. Security Ownership of Certain Beneficial Owners and Management
	Item 13. Certain Relationships and Related Transactions
PART IV
	Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
SIGNATURES
EXHIBIT INDEX
EXHIBIT 3.1
EXHIBIT 10.12
EXHIBIT 10.13
EXHIBIT 10.14
EXHIBIT 10.15
EXHIBIT 10.126
EXHIBIT 12.1
EXHIBIT 21.1
EXHIBIT 23.1
EXHIBIT 23.2
EXHIBIT 24.1
EXHIBIT 24.2
EXHIBIT 24.3
EXHIBIT 24.4
EXHIBIT 24.5
EXHIBIT 24.6
EXHIBIT 24.7
EXHIBIT 24.8
EXHIBIT 24.9
EXHIBIT 24.10
EXHIBIT 24.11
EXHIBIT 24.12
EXHIBIT 24.13
EXHIBIT 24.14
EXHIBIT 24.15
EXHIBIT 24.16
EXHIBIT 24.17
EXHIBIT 99.1
EXHIBIT 99.3

TABLE OF CONTENTS


Item			Page No.

PART I
	1.	Business		1
		(a) General Development of Business		1
		(b) Description of Business and Properties		2
		Capital and Exploratory Expenditures		3
		Petroleum – Exploration and Production		4
		Liquids and Natural Gas Production		4
		Acreage		5
		Reserves and Contract Obligations		6
		Development Activities		7
		Exploration Activities		9
		Review of Ongoing Exploration and Production Activities In Key Areas		9
		Petroleum – Natural Gas Liquids		14
		Petroleum – Refining		14
		Petroleum – Refined Products Marketing		16
		Petroleum – Transportation		17
		Energy Marketing and Services – Dynegy		18
		Chemicals		19
		Coal		19
		Other Activities – Synthetic Crude Oil		19
		Power and Gasification		20
		Research and Technology		20
		Environmental Protection		20
	2.	Properties		21
	3.	Legal Proceedings		21
	4.	Submission of Matters to a Vote of Security Holders		22
		Executive Officers of the Registrant		22
PART II
	5.	Market for the Registrant’s Common Equity and Related Stockholder Matters		23
	6.	Selected Financial Data		24
	7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
	7A.	Quantitative and Qualitative Disclosures About Market Risk		24
	8.	Financial Statements		24
	8.	Supplementary Data – Quarterly Results		24
		– Oil and Gas Producing Activities		24
	9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		24
PART III
	10.	Directors and Executive Officers of the Registrant		24
	11.	Executive Compensation		24
	12.	Security Ownership of Certain Beneficial Owners and Management		25
	13.	Certain Relationships and Related Transactions		25
PART IV
	14.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K		25
		Schedule II – Valuation and Qualifying Accounts		26

PART I

Item 1. Business

(a) General Development of Business

Summary Description of ChevronTexaco

ChevronTexaco Corporation¹, a Delaware corporation, manages its investments in subsidiaries and affiliates, and provides administrative, financial and management support to, U.S. and foreign subsidiaries that engage in fully integrated petroleum operations, chemicals operations, coal mining, power and energy services. The company operates in the United States and approximately 180 other countries. Petroleum operations consist of exploring for, developing and producing crude oil and natural gas; refining crude oil into finished petroleum products; marketing crude oil, natural gas and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipelines, marine vessels, motor equipment and rail car. Chemicals operations include the manufacture and marketing, by an affiliate, of commodity petrochemicals and plastics for industrial uses, and the manufacture and marketing, by a consolidated subsidiary, of fuel and lubricating oil additives.

In this report, exploration and production of crude oil, natural gas liquids and natural gas may be referred to as “E&P” or “upstream” activities. Refining, marketing and transportation may be referred to as “RM&T” or “downstream” activities. A list of the company’s major subsidiaries is presented on page E-2 of this Annual Report on Form 10-K. As of December 31, 2001, ChevronTexaco had 55,763 employees (excluding 11,806 service station employees), down about 1,600 from year-end 2000. Included in this net change between periods was an addition of about 1,000 employees who had previously been classified as contractors in certain international operations. Approximately 32,000, or 47 percent, of the company’s employees, including service station employees, were employed in U.S. operations, of which approximately 4,500 were unionized.

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE

PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

Among the factors that could cause actual results to differ materially are crude oil and natural gas prices; refining margins and marketing margins; chemicals prices and competitive conditions affecting supply and demand for aromatics, olefins and additives products; actions of competitors; the competitiveness of alternate energy sources or product substitutes; technological developments; inability of the company’s joint-venture partners to fund their share of operations and development activities; potential failure to achieve expected production from existing and future oil and gas development projects; potential delays in the development, construction or start-up of planned projects; the successful integration of the former Chevron, Texaco and Caltex businesses; potential disruption or interruption of the company’s production or manufacturing facilities due to accidents or political events; potential liability for remedial actions under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental regulations (including, particularly, regulations and litigation dealing with gasoline composition and characteristics); and potential liability resulting from pending or future litigation. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

¹ Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. As used in this report, the term “ChevronTexaco” and such terms as “the company,” “the corporation,” “our,” “we,” and “us” may refer to ChevronTexaco Corporation, one or more of its consolidated subsidiaries, or to all of them taken as a whole, but unless it is stated otherwise, does not include “affiliates” of ChevronTexaco – i.e., those companies accounted for by the equity method (generally owned 50 percent or less), or investments accounted for by the cost method. All of these terms are used for convenience only, and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.

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Overview of Petroleum Industry

Petroleum industry operations and profitability are influenced by many factors, over some of which individual petroleum companies have little control. Governmental policies, particularly in the areas of taxation, energy and the environment, have a significant impact on petroleum activities, regulating where and how companies conduct their operations and formulate their products and, in some cases, limiting their profits directly. Prices for crude oil and natural gas, petroleum products and petrochemicals are determined by supply and demand for these commodities. The members of the Organization of Petroleum Exporting Countries (OPEC) are typically the world’s swing producers of crude oil, and their production levels are a major factor in determining worldwide supply. Demand for crude oil and its products and natural gas is largely driven by the conditions of local, national and worldwide economies, although weather patterns and taxation relative to other energy sources also play a significant part. Natural gas is generally produced and consumed on a country or regional basis.

Operating Environment

Refer to page FS-2 of this Annual Report on Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion on the company’s current business environment and outlook.

Texaco Merger Transaction

On October 9, 2001, Texaco Inc. (Texaco) became a wholly owned subsidiary of Chevron Corporation (Chevron) pursuant to a merger transaction, and Chevron changed its name to ChevronTexaco Corporation. The combination was accounted for as a pooling of interests, and each share of Texaco common stock was converted on a tax-free basis into the right to receive 0.77 shares of ChevronTexaco common stock. In the merger, ChevronTexaco issued approximately 425 million shares of common stock, representing about 40 percent of the outstanding ChevronTexaco common stock after the merger. Further discussion of the Texaco merger transaction, including merger-related expenses and synergy savings, is contained on pages FS-2 and FS-3 of this Annual Report on Form 10-K.

ChevronTexaco Strategic Direction

ChevronTexaco’s primary strategic objective is to achieve the highest total stockholder return in its peer group for the five-year period 2000 - 2004. British Petroleum, ExxonMobil and Royal Dutch Shell are the primary competition where ChevronTexaco operates and comprise the company’s competitor peer group. The company had the highest total stockholder return in its peer group for the 2000 - 2001 period.

As a foundation for attaining this goal, the company has established four key priorities:

• Operational excellence through safe, reliable, efficient and environmentally sound operations;

• Cost reduction by lowering unit costs through innovation and technology;

• Capital stewardship by investing in the best project opportunities and executing them successfully (safer, faster, at lower cost); and

• Profitable growth through leadership in developing new business opportunities in both existing and new markets.

Supporting these four priorities is a continued and improved focus on:

• Organizational Capability: The company has developed strategies to build capability systems to achieve top performance in the four priorities described above.

(b) Description of Business and Properties

The company’s largest business segments are exploration and production, and refining, marketing and transportation. Chemicals is also a significant operation, conducted mainly by the company’s affiliate – Chevron Phillips Chemical Company LLC (CPChem). The petroleum activities of the company are

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widely dispersed geographically. The company has petroleum operations in North America, South America, Europe, Africa, Middle East, Central and Far East Asia, and Australia.

CPChem has operations in the United States, Belgium, China, South Korea, Singapore, Saudi Arabia, Qatar and Mexico. The company’s wholly owned Oronite additives business has operations in the United States, France, Netherlands, Singapore, Japan and Brazil.

An affiliate, Dynegy Inc. (Dynegy), is one of the leading marketers of energy products and services in the United States with customers in the United States, Canada, the United Kingdom (U.K.) and other European countries. Its business activities include energy marketing; independent power generation; gathering, processing, selling and transportation of natural gas and natural gas liquids; and broadband trading.

Tabulations of segment sales and other operating revenues, earnings, income taxes and assets, by United States and International geographic areas, for the years 1999 to 2001, may be found in Note 11 to the consolidated financial statements beginning on page FS-28 of this Annual Report on Form 10-K. In addition, similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are contained in Notes 14 and 15 on pages FS-31 to FS-33.

The company’s worldwide operations can be affected significantly by changing economic, tax, regulatory and political environments in the various countries in which it operates, including the United States. Environmental regulations and government policies concerning economic development, energy and taxation may have a significant effect on the company’s operations. Management evaluates the economic and political risk of initiating, maintaining or expanding operations in any geographical area. The company monitors political events worldwide and the possible threat these may pose to its activities – particularly the company’s oil and gas exploration and production operations – and the safety of the company’s employees.

The company attempts to avoid unnecessary involvement in partisan politics in the communities in which it operates, but participates in the political process to safeguard its assets and to ensure that the community benefits from its operations and remains receptive to its continued presence.

Capital and Exploratory Expenditures

A discussion of the company’s capital and exploratory expenditures is contained on page FS-10 of this Annual Report on Form 10-K.

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Petroleum – Exploration and Production

Liquids and Natural Gas Production

The following table summarizes the company’s and affiliates’ net production of crude oil and natural gas liquids, and natural gas for 2001 and 2000.

Net Production¹ Of Crude Oil And Natural Gas Liquids And Natural Gas



		Crude Oil &
		Natural Gas Liquids				Natural Gas
		(Thousands of				(Millions of
		Barrels per Day)				Cubic Feet per Day)

		2001		2000		2001		2000

United States:
	California		249		266		116		118
	Gulf of Mexico		187		179		1,023		1,130
	Texas		87		110		598		660
	Wyoming		11		15		220		225
	Other States		80		97		749		777

Total United States			614		667		2,706		2,910

Africa:
Angola			168		169		1		1
Nigeria			158		155		43		47
Republic of Congo			20		25		—		—
Democratic Republic of Congo			9		8		—		—
Asia-Pacific:
Indonesia			304		319		134		133
Partitioned Neutral Zone (PNZ)²			144		139		10		11
Australia			45		48		235		225
Kazakhstan			17		17		67		83
Thailand			16		14		75		70
Papua New Guinea			7		11		—		—
Philippines			1		—		9		—
China			24		28		—		—
Other International:
United Kingdom (North Sea)			115		117		350		342
Canada			64		66		167		146
Argentina			57		51		56		51
Denmark			39		39		100		98
Norway			17		15		4		1
Venezuela			4		4		4		—
Colombia			—		1		203		194
Trinidad			—		8		100		65
Netherlands			—		—		1		1

Total International			1,209		1,234		1,559		1,468

Total Consolidated Operations			1,823		1,901		4,265		4,378
Equity in Affiliates			136		96		152		88

Total Including Affiliates			1,959		1,997		4,417		4,466

¹ Net production excludes royalty interests owned by others.

² Located between the Kingdom of Saudi Arabia and the State of Kuwait.

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In 2001, ChevronTexaco conducted its worldwide exploration and production operations in the United States and approximately 25 other countries. Worldwide net crude oil and natural gas liquids production, including that of affiliates but excluding volumes produced under operating service agreements, decreased by about 2 percent from the 2000 levels. Net worldwide production of natural gas, including affiliates, fell 1 percent in 2001. Net liquids and natural gas production in the United States was down about 8 percent and 7 percent, respectively. The lower production reflected normal field declines and asset sales, partially offset by new and enhanced production in the deepwater and other areas of the Gulf of Mexico. International net liquids production, including affiliates, increased about 1 percent, while net natural gas production rose 10 percent from 2000. The increase in gas production occurred primarily in Trinidad, Canada and the company’s Tengizchevroil (TCO) affiliate in Kazakhstan.

While worldwide oil-equivalent production in 2001 was down less than 2 percent from 2000 levels, the company has targeted an oil-equivalent production growth rate over the next five years of 2.5 to 3 percent annually. However, 2002 production is expected to increase only about 1 percent because of OPEC-related constraints.

Acreage

At December 31, 2001, the company owned or had under lease or similar agreements undeveloped and developed oil and gas properties located throughout the world. The geographical distribution of the company’s acreage is shown in the next table.

Acreage¹ At December 31, 2001

(Thousands of Acres)



									Developed
									and
	Undeveloped²				Developed²				Undeveloped

	Gross		Net		Gross		Net		Gross		Net

United States		10,457		7,462		8,508		4,152		18,965		11,614

Africa		25,556		8,751		411		116		25,967		8,867
Asia-Pacific		53,619		25,384		1,683		590		55,302		25,974
Other International		51,545		27,132		2,400		859		53,945		27,991

Total International		130,720		61,267		4,494		1,565		135,214		62,832

Total Consolidated Companies		141,177		68,729		13,002		5,717		154,179		74,446
Equity in Affiliates		927		464		57		28		984		492

Total Including Affiliates		142,104		69,193		13,059		5,745		155,163		74,938

¹ Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage is the sum of the company’s fractional interests in gross acreage.

² Developed acreage is spaced or assignable to productive wells. Undeveloped acreage is acreage where wells have not been drilled or completed to permit commercial production, and may contain undeveloped proved reserves.

Refer to Table IV on page FS-48 of this Annual Report on Form 10-K for data about the company’s average sales price per unit of oil and gas produced, as well as the average production cost per

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unit for 2001, 2000 and 1999. The following table summarizes gross and net productive wells at year-end 2001 for the company and its affiliates.

Productive Oil And Gas Wells At December 31, 2001



	Productive¹				Productive¹
	Oil Wells				Gas Wells

	Gross²		Net²		Gross²		Net²

United States		43,368		26,868		11,075		5,533

Africa		1,386		544		5		2
Asia-Pacific		8,396		7,537		269		141
Other International		2,248		1,400		382		171

Total International		12,030		9,481		656		314

Total Consolidated Companies		55,398		36,349		11,731		5,847
Equity in Affiliates		106		43		—		—

Total Including Affiliates		55,504		36,392		11,731		5,847

Multiple completion wells included above:		617		338		350		218

¹ Includes wells producing or capable of producing and injection wells temporarily functioning as producing wells. Wells that produce both oil and gas are classified as oil wells.

² Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company’s fractional interests in gross wells.

Reserves and Contract Obligations

Table V on pages FS-48 and FS-49 of this Annual Report on Form 10-K sets forth the company’s net proved oil and gas reserves, by geographic area, as of December 31, 2001, 2000 and 1999. During 2002, the company will file estimates of oil and gas reserves with the Department of Energy, Energy Information Agency. Those estimates are consistent with the reserve data reported on page FS-49 of this Annual Report on Form 10-K.

In 2001, ChevronTexaco’s worldwide oil and equivalent-gas (BOE) barrels of net proved reserves additions exceeded production, with a replacement rate of 127 percent of net production, including sales and acquisitions. Excluding sales and acquisitions, the replacement rate was 112 percent of net production. In the United States, the reserves replacement rate was impacted by a significant downward revision in proved crude oil reserve quantities for the Midway Sunset Field in California’s San Joaquin Valley. The revision was the result of a determination of lower-than-projected oil recovery from the field’s steam

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injection process. The following table summarizes the company’s net additions to net proved reserves of crude oil and natural gas liquids and natural gas, compared with net production during 2001.

Reserves Replacement – 2001



	Additions to					Net							Memo:
	Reserves					Production				BOE			Replacement %
										Reserves			Including
	Liquids			Gas		Liquids		Gas		Replacement			Sales and
	(mmbbls)¹			(bcf)²		(mmbbls)¹		(bcf)²		%			Acquisitions

United States		(89	)		452		224		988		5	%		(3	)%
Africa		168			1,116		129		16		268	%		268	%
Asia-Pacific		216			511		204		194		126	%		127	%
Other international³		424			1,100		157		415		190	%		269	%

Total Worldwide		719			3,179		714		1,613		112	%		127	%

¹ mmbbls = millions of barrels

² bcf = billions of cubic feet

³ Includes equity in affiliates

The company sells crude oil and natural gas from its producing operations under a variety of contractual arrangements. Most contracts generally commit the company to sell quantities based on production from specified properties but certain gas sales contracts specify delivery of fixed and determinable quantities. Dynegy and ChevronTexaco have entered into long-term strategic alliances whereby Dynegy purchases substantially all natural gas and natural gas liquids produced by legacy Chevron in the United States, excluding Alaska, and supplies natural gas and natural gas liquids feedstocks to the company’s U.S. refineries and chemical plants. In March 2002, the company reached agreement with Dynegy to expand those contracts to include substantially all of legacy Texaco’s U.S. natural gas and natural gas liquids production. Outside the United States, the company is contractually committed to deliver approximately 110 billion cubic feet of natural gas through 2004 from both Australian and U.K. reserves, and approximately 335 billion cubic feet of natural gas post-2004 through 2020 from Australian reserves only. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed Australian and U.K. natural gas reserves. Substantially all of the contracts discussed above include variable-pricing terms.

Development Activities

Details of the company’s development expenditures and costs of proved property acquisitions for 2001, 2000 and 1999 are presented in Table I on page FS-45 of this Annual Report on Form 10-K.

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The table below summarizes the company’s net interest in productive and dry development wells completed in each of the past three years and the status of the company’s development wells drilling at December 31, 2001. A “development well” is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. “Wells drilling” include wells temporarily suspended.

Development Well Activity



					Net Wells Completed¹
	Wells
	Drilling
	At 12/31/01				2001				2000				1999

	Gross²		Net²		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States		373		137		866		21		919		14		857		14

Africa		33		13		22		—		39		—		19		—
Asia-Pacific		16		11		555		—		501		1		530		1
Other International		32		19		109		2		113		—		30		—

Total International		81		43		686		2		653		1		579		1

Total Consolidated Companies		454		180		1,552		23		1,572		15		1,436		15
Equity in Affiliates		37		18		17		—		33		—		1		—

Total Including Affiliates		491		198		1,569		23		1,605		15		1,437		15

¹ Indicates the number of wells completed during the year regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of oil or gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency.

² Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company’s fractional interests in gross wells.

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Exploration Activities

The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the last three years and the number of exploratory wells drilling at December 31, 2001.

Exploratory Well Activity



					Net Wells Completed¹
	Wells
	Drilling
	At 12/31/01				2001				2000				1999

	Gross²		Net²		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States		42		28		101		32		69		30		90		40

Africa		4		1		8		2		2		4		2		2
Asia-Pacific		10		4		31		8		15		11		6		12
Other International		12		8		6		10		7		7		8		5

Total International		26		13		45		20		24		22		16		19

Total Consolidated Companies		68		41		146		52		93		52		106		59
Equity in Affiliates		1		—		14		—		—		—		—		—

Total Including Affiliates		69		41		160		52		93		52		106		59

“Exploratory wells” are wells drilled to find and produce oil or gas in unproved areas and include delineation wells, which are wells drilled to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir beyond the proved area. “Wells drilling” include wells temporarily suspended. The company had $783 million of suspended exploratory wells included in properties, plant and equipment at year-end 2001, a decrease of $87 million from 2000. Decreases in the United States, United Kingdom, Australia and Angola were partially offset by increases in Nigeria, Brazil and China. The wells are suspended pending a final determination of the commercial potential of the related oil and gas fields. The ultimate disposition of these well costs is dependent on: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory drilling that is underway or firmly planned, and in some cases, (3) securing final regulatory approvals for development.

Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2001, 2000 and 1999 are presented in Table I on page FS-45 of this Annual Report on Form 10-K.

Review of Ongoing Exploration and Production Activities in Key Areas

ChevronTexaco’s 2001 key upstream activities not discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations beginning on page FS-2 of this Annual Report on Form 10-K are presented below. The comments include reference to “net production,” which excludes partner shares and royalty interests. “Total production” includes these components. In addition to the activities discussed, ChevronTexaco was active in other geographic areas, but these activities were less significant.

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Consolidated Operations

A) United States

United States exploration and production activities are concentrated in nearly 850 fields located mainly in the Gulf of Mexico, Texas, New Mexico, the Rocky Mountains, California and Alaska.

Gulf of Mexico: In the Gulf of Mexico Shelf, the company maintained average net production rates of 142,000 barrels of oil, 1.237 billion cubic feet of gas, and 14,200 barrels of natural gas liquids per day.

In the Gulf of Mexico deepwater, ChevronTexaco has interests in three significant developments. The company operates and has a 57 percent interest in Genesis, which averaged net daily oil-equivalent production of 33,000 barrels during the year. Production began in July 2001 at a second development, Typhoon, in which the company has a 50 percent interest. Net daily production averaged nearly 18,000 barrels of oil-equivalent during the fourth quarter 2001. ChevronTexaco has a 50 percent interest in a third deepwater development, Petronius, which averaged net oil-equivalent production of 27,000 barrels per day during 2001. Exploration programs resulted in discoveries at Trident, Boris and Blind Faith, and confirmation of the 2000 Champlain discovery. The Trident appraisal is ongoing.

Mid-Continent/ Permian Basin: Onshore operations in the mid-continent United States are located in Utah, Texas, and Wyoming. Net natural gas production averaged 921 million cubic feet per day, while net production of crude oil and natural gas liquids averaged 31,000 barrels per day. Capital spending was focused on natural gas development and coalbed methane activity, located in northeast Utah. Permian Basin operations are located primarily in New Mexico. In 2001, net daily production averaged 117,500 barrels of crude oil and natural gas liquids and 275 million cubic feet of natural gas.

California: During 2001, average net daily production from the company’s San Joaquin Valley fields was 245,100 barrels of crude oil, 116 million cubic feet of natural gas and 3,900 barrels of natural gas liquids. Approximately 210,000 barrels per day of the crude oil production was heavy oil.

Offshore Florida: Development of the Destin Dome area of the Norphlet trend offshore Florida continues to be hampered by delays in obtaining regulatory approvals. A draft environmental impact statement was issued in August 1999 by the governing agencies indicating no significant environmental impacts from the project. In July 2000, ChevronTexaco and its partners in the Destin Dome development filed a lawsuit against the federal government to recover exploration expense and future lost profits following continuing delays in obtaining the necessary development permits. The company has filed a motion for summary judgement, which could decide the liability portion of the case and leave the amount of damages to be decided later.

B) Africa

Nigeria: ChevronTexaco’s principal subsidiary in Nigeria, Chevron Nigeria Limited (CNL), operates and holds a 40 percent interest in 11 concessions, predominantly in the swamp and near-offshore regions of the Niger Delta. CNL operates under a joint venture arrangement with the Nigerian National Petroleum Corporation (NNPC), which owns the remaining 60 percent interest. ChevronTexaco’s subsidiaries Chevron Oil Company Nigeria Limited (COCNL) and Texaco Overseas Nigeria Petroleum Company Unlimited (TOPCON) each hold a 20 percent interest in six concessions. TOPCON operates these concessions under a joint venture agreement with NNPC, which owns the remaining 60 percent interest.

In 2001, daily net production from the 33 CNL-operated fields averaged 143,000 barrels of oil and 2,700 barrels of liquefied petroleum gas (LPG). During 2001, net production from the six TOPCON-operated fields averaged approximately 12,000 barrels of oil per day.

Phase 2 of the Escravos gas project was completed in the first quarter 2001. As a result, processing capacity at the plant increased to 285 million cubic feet per day. Preliminary design for Phase 3, which includes adding a second gas plant and expanding processing capacity to 680 million cubic feet per day,

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started in the third quarter of 2001 and is targeted for completion in 2005. ChevronTexaco holds a 40 percent working interest in the Escravos gas project.

Feasibility engineering and preliminary technical evaluations have been completed for a proposed gas-to-liquids (GTL) plant at Escravos. Front-end engineering and design started in March 2001. The proposed 33,000 barrels-per-day (12,000 barrels per day net) GTL project is the first to use the Sasol Chevron Global Joint Venture’s technology and operational expertise. Project start-up is expected to be in 2005. ChevronTexaco holds a 37.5 percent interest.

Angola: ChevronTexaco is the largest producer in Angola and the first to produce in the deepwater. Cabinda Gulf Oil Company Limited (CABGOC), a wholly owned subsidiary of ChevronTexaco, is operator of two concessions, Blocks 0 and 14, off the coast of Angola’s Cabinda enclave. Block 0, in which CABGOC has a 39 percent interest, is a 2,100-square-mile concession adjacent to the Cabinda coastline. Block 14, in which CABGOC has a 31 percent interest, is a 1,560-square-mile deepwater concession located west of Block 0.

In Block 0, the company operates in 3 areas – A, B and C. Area A, containing 15 fields currently producing, averaged net production of approximately 96,000 barrels of crude oil per day in 2001. Area B, with 3 fields producing, averaged net production of 32,500 barrels of crude oil per day. Area C averaged net production of 10,500 barrels of crude oil per day from 7 fields. Major development projects during 2001 included phase 1 of a waterflood project in Area A and a production and gas injection platform in the Area B North Nemba Field.

In Block 14, net production in 2001 from the Kuito Field, Angola’s first deepwater producing area, averaged approximately 19,000 barrels of crude oil per day. Development plans are under way for other fields within the Block.

Texaco Panama Angola Inc., a subsidiary of ChevronTexaco, is operator of and has a 20 percent interest in Block 2, a 160-square-mile concession adjacent to the northwestern part of Angola’s coast. Average net daily production from Block 2 was about 7,000 barrels of crude oil in 2001.

The company operates and has a 40 percent interest in offshore exploration Blocks, 9 and 22, which encompass approximately 2,000-square-miles each and are located south of Luanda, Angola’s capital.

Republic of Congo: ChevronTexaco has interests in two license areas, Haute Mer and Kitina/ Sounda, in offshore Congo and adjacent to the company’s concessions in Cabinda. ChevronTexaco has a 30 percent interest in the Haute Mer exploration permit and a 29 percent interest in the Kitina/ Sounda exploitation permits. The company’s interest in the deepwater Mer Profonde Sud license area was relinquished in 2001. Net production from ChevronTexaco’s concessions in the Republic of Congo averaged 20,000 barrels per day in 2001. Field development studies continue for the deepwater Moho and Bilondo discoveries in Haute Mer. Appraisal drilling was underway in early 2002.

Chad-Cameroon: ChevronTexaco is a 25 percent partner in a project that will develop landlocked oil fields in southern Chad and transport crude oil by pipeline to the coast of Cameroon for export to world markets. Project financing was secured during the second quarter 2001. At the end of 2001, the overall development project was about one-third complete. Pipeline construction began in the fourth quarter and drilling initiated in the first quarter 2002. First production is expected in 2004.

Equatorial Guinea: ChevronTexaco is a 65 percent partner and operator of the L Block offshore the Republic of Equatorial Guinea. The initial 3D seismic survey was completed in 2001 and is presently being analyzed.

C) Asia-Pacific

Indonesia: ChevronTexaco’s interests in Indonesia are managed by two wholly owned subsidiaries, PT Caltex Pacific Indonesia (CPI) and Amoseas Indonesia (AI). CPI accounts for approximately 50 percent of Indonesia’s total crude oil output and holds an interest in six production-sharing contracts. AI is a power generation company that operates the Darajat geothermal contract area in West Java and a

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cogeneration facility in support of CPI’s operation in North Duri. ChevronTexaco’s net share of production during 2001 averaged about 320,000 barrels of crude oil and condensate per day. CPI continues to implement enhanced oil recovery projects to extract more oil from its existing reservoirs. The Duri Field in the Rokan Block, under steamflood since 1985, is the largest steamflood project in the world. Currently 9 of 13 areas are under steam injection, with total production averaging about 260,000 barrels of oil per day during 2001. Area 10 is currently under development and will be placed on injection in the second quarter of 2002. CPI was awarded a new production-sharing contract for the Kisaran Block in 2001. The block is located in a gas prospective basin adjacent to the Rokan Block. A seismic review is planned for 2002.

Thailand: The company operates Block B8/32 in the Gulf of Thailand with a 52 percent interest. The company holds a 33 percent interest in adjacent exploration Blocks 7, 8 and 9, which are currently inactive pending resolution of border issues between Thailand and Cambodia. Block B8/32 produces oil and natural gas from three fields: Tantawan, Maliwan, and Benchamas. Initial production from the Maliwan Field occurred in October 2001. Net average daily production during 2001 from the company’s interests in Thailand was 75 million cubic feet of natural gas and 16,000 barrels of crude oil. In 2002, the Benchamas Field will go through a major processing upgrade to bring total field production levels up to 60,000 barrels of oil per day. Development of the Maliwan Field will continue with production from multiple platforms expected to begin in 2005. Nine of the 11 exploration wells drilled in 2001 were successful, extending the productive areas in Block B8/32 significantly. During 2002, an exploration program is planned to evaluate the remaining portions of the concession.

Australia: ChevronTexaco has a one-sixth interest in the North West Shelf (NWS) Project in offshore Western Australia. Average daily net production from the NWS Project during 2001 was 230 million cubic feet of natural gas and 16,000 barrels per day of condensate. Net crude oil production from the NWS Project averaged approximately 17,000 barrels per day and total LPG production averaged about 4,000 barrels per day. Approximately 68 percent of the natural gas was sold, primarily under long-term contracts, in the form of liquefied natural gas (LNG) to major utilities in Japan. The remaining gas was sold to the Western Australia domestic gas market. In 2001, ChevronTexaco approved the development of the Train 4 LNG expansion project, which is planned to increase LNG capacity by about 50 percent in 2004. The North West Shelf Venture LNG sellers have secured LNG Sales and Purchase Agreements and Letters of Intent with several Japanese customers, for a total volume equal to the capacity of the new LNG Train.

The company is operator and has a 57 percent interest in the undeveloped Gorgon area gas field offshore north-west Australia. ChevronTexaco is actively pursuing long-term gas sales from Gorgon to Australian industrial customers and in international LNG markets including China, Korea, and the west coast of North America.

Philippines: ChevronTexaco holds a 45 percent interest in the Malampaya gas field located about 50 miles offshore of the Palawan Island. The Malampaya gas-to-power project represents the first offshore production of natural gas in the Philippines. In September 2001 production commenced. The gas will be delivered to three power plants under Gas Sales and Purchase Agreements. Gas sales are projected to increase throughout 2002 as the power plants are commissioned and brought into commercial operation.

Middle East: ChevronTexaco holds a concession with the Kingdom of Saudi Arabia to produce onshore crude oil from the Partitioned Neutral Zone (PNZ). The Kingdom of Saudi Arabia and the State of Kuwait each own 50 percent of the hydrocarbon resources. ChevronTexaco is entitled to 50 percent of the gross field production, for which it pays a royalty and other taxes to the Kingdom of Saudi Arabia. During 2001, record production was achieved from the four producing fields – averaging 144,000 net barrels of crude oil per day. Planned development drilling, workover, and facilities enhancement programs during the next few years are expected to maintain production at similar levels. The company also has exploration agreements in Bahrain and Qatar.

Caspian Region: The company holds a 20 percent equity interest in the Karachaganak Field located in northwest Kazakhstan. Net daily production for 2001 was 14,300 barrels of condensate and 67 million cubic feet of gas from the existing production facilities. The current phase of the Karachaganak

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development includes the building of processing and liquid export facilities to be completed by the end of 2003.

D) Other International Areas

Europe: The company holds producing interests in 24 fields in Denmark, Norway and the United Kingdom. The combined net average daily production during 2001 was 171,000 barrels of crude oil and condensate and 454 million cubic feet of natural gas. The Alba Field in the United Kingdom North Sea, where ChevronTexaco is operator and holds a 21 percent equity interest, produced a net average of 17,000 net barrels of crude oil and 2.8 million cubic feet of natural gas per day. Development of the Alba Extreme South project, which is expected to begin production in late 2002, will maintain the Alba Field’s total production of 80,000 barrels of crude oil per day. ChevronTexaco holds an approximate 32 percent interest in the Britannia Field and shares operatorship. Net production averaged 9,600 barrels of crude oil and condensate per day and 208 million cubic feet of natural gas per day. The Captain Field net daily production averaged 49,000 barrels of crude oil during 2001. ChevronTexaco is operator and holds an 85 percent interest.

In Denmark, ChevronTexaco holds a 15 percent interest in the Danish Underground Consortium (DUC) currently producing crude oil and natural gas from 14 fields in the Danish North Sea. The DUC also holds nine exploration licenses with company interests ranging from 12 to 27 percent.

Canada: Total production from the Hibernia Field offshore Newfoundland, in which ChevronTexaco holds an interest of about 27 percent, averaged approximately 151,000 barrels of crude oil per day. Average net daily production from the company’s onshore Canadian operations was 52,000 barrels of oil equivalent during 2001.

Venezuela: The company operates the onshore Boscan Field, located near the city of Maracaibo, under an Operating Services Agreement and receives operating expense reimbursement and capital recovery, plus interest and an incentive fee. Development drilling continued in 2001. Boscan crude oil production, subject to Venezuela’s OPEC production restrictions, averaged 104,800 barrels per day during 2001. The company is also the operator and has a 27 percent interest in the LL-652 Field in Lake Maracaibo. Net production from LL-652 during 2001 averaged 4,900 barrels of oil per day, up from 4,000 barrels of oil per day in 2000. Field performance during 2001 indicated slower than anticipated re-pressurization of the reservoir by water injection and a reduction in the projected volumes of crude oil recoverable during the company’s remaining contract period of operations. As a result the company wrote down proved crude oil reserve quantities at LL-652 in 2001.

Argentina: ChevronTexaco operates in Argentina as Chevron San Jorge S.R.L. Chevron San Jorge holds more than 6.1 million exploration and production acres in the Neuquén and Austral basins of Argentina, with working interest shares ranging from 18 to 100 percent in operated license areas. In addition, the company holds a 14 percent interest in Oleoductos del Valle S.A. (Oldeval), a major oil export pipeline from the Neuquén producing area to the Atlantic coast. Daily net production during 2001 in the Neuquén and Austral areas averaged over 66,000 net barrels of oil-equivalent, an increase of over 11 percent from 2000 production levels.

Brazil: ChevronTexaco holds working interests ranging from 20 to 50 percent in nine deepwater blocks offshore Brazil totaling approximately 9.2 million acres. Deepwater exploration is concentrated in the Campos, Santos, and Espirito Santo basins. During 2001, the company drilled two successful appraisal wells in the Frade Field in Block BC-4 of the Campos Basin. ChevronTexaco’s interest in the Frade Block is approximately 43 percent. In the non-operated Block BS-4, where ChevronTexaco holds a 20 percent interest, two exploratory wells were drilled during 2001. One well resulted in a discovery.

Affiliate operations

Caspian Region: The Tengizchevroil (TCO) partnership, formed in 1993, includes the Tengiz and Korolev oil fields located in western Kazakhstan. In January 2001, the company acquired an additional

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5 percent stake in TCO, increasing its ownership interest to 50 percent. In 2001, total crude oil production from TCO increased for the eighth consecutive year, averaging 268,000 barrels of oil per day. Engineering for TCO’s next major expansion, expected to come on-line during 2005, is under way. Production at Korolev, located near Tengiz, began in November 2001. Crude oil from the field is very similar to crude produced from Tengiz and is routed to existing facilities at TCO through an extension of an existing gathering system.

Venezuela: ChevronTexaco has a 30 percent interest in the Hamaca integrated oil production and upgrading project located in Venezuela’s Orinoco Belt. Development drilling and major facility construction at Hamaca continued throughout 2001. Early production was established in October 2001, at a net rate of 9,000 barrels of crude oil per day. At the completion of the crude oil upgrading facilities in the first half of 2004, field production will increase to 190,000 barrels of crude oil per day and will be lighter, high-value crude.

Petroleum – Natural Gas Liquids

The company sells natural gas liquids from its producing operations under a variety of contractual arrangements. In the United States, the majority of sales are to the company’s affiliate, Dynegy. Dynegy and ChevronTexaco have entered into long-term strategic alliances whereby Dynegy purchases substantially all natural gas and natural gas liquids produced by legacy Chevron in the United States, excluding Alaska, and supplies natural gas and natural gas liquids feedstocks to the company’s U.S. refineries and chemical plants. In March 2002, the company reached agreement with Dynegy to expand those contracts to include substantially all of legacy Texaco’s U.S. natural gas and natural gas liquids production. Outside the United States, natural gas liquids sales take place in the company’s Canadian upstream operations, with lower sales levels in Africa, Australia and Europe.

Refer to “Selected Operating Data” on page FS-7 of this Annual Report on Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for further information on the company’s natural gas liquids sales volumes.

Petroleum – Refining

Distillation operating capacity utilization in 2001, adjusted for sales and closures, averaged 88 percent in the United States (including asphalt plants) and 87 percent worldwide (including affiliates), compared with 88 percent in the United States and worldwide in the prior year. ChevronTexaco’s capacity utilization at its U.S. fuels refineries averaged 90 percent in 2001, compared with 91 percent in 2000. ChevronTexaco’s capacity utilization of its wholly-owned U.S. cracking and coking facilities, which are the primary facilities used to convert heavier products to gasoline and other light products, averaged 84 percent in 2001, up from 80 percent in the year earlier. The company processed imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for 68 percent of ChevronTexaco’s U.S. refinery inputs in 2001.

Prior to October 2001, the company had interests in eight U.S. refineries with a combined capacity of about 1.3 million barrels per day through its investments in the Equilon and Motiva affiliates. These investments were placed in trust in October 2001, and sold, as required by the U.S. Federal Trade Commission, in February 2002.

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The daily refinery inputs over the last three years for the company and affiliate refineries are shown in the following table:

Petroleum Refineries: Locations, Capacities And Inputs

(Inputs and Capacities are in Thousands of Barrels Per Day)



		December 31,
		2001
						Refinery Inputs
				Operable
Locations		Number		Capacity		2001		2000		1999


Pascagoula	Mississippi		1		295		332		313		328
El Segundo	California		1		260		213		219		211
Richmond	California		1		225		229		203		207
El Paso¹	Texas		1		65		61		60		65
Honolulu	Hawaii		1		54		54		51		51
Salt Lake City	Utah		1		45		44		44		43
Other²			2		96		50		53		50

Total Consolidated Companies – United States			8		1,040		983		943		955

Equity in Affiliates³	Various Locations		—		—		353		447		579

Total Including Affiliates – United States			8		1,040		1,336		1,390		1,534

Pembroke	United Kingdom		1		210		202		215		195
Cape Town	South Africa		1		112		71		65		73
Batangas	Philippines		1		76		65		65		70
Colón⁴	Panama		1		60		54		44		49
Burnaby, B.C.,	Canada		1		52		52		51		52
Escuintla	Guatemala		1		17		16		16		17

Total Consolidated Companies – International			6		527		460		456		456

Equity in Affiliates⁵	Various Locations		11		781		676		694		779

Total Including Affiliates – International			17		1,308		1,136		1,150		1,235

Total Including Affiliates – Worldwide			25		2,348		2,472		2,540		2,769

¹ Capacity and input amounts for El Paso represent ChevronTexaco’s share.

² Refineries in Perth Amboy, New Jersey and Portland, Oregon, which are primarily asphalt plants.

³ Represents ChevronTexaco interests in Equilon and Motiva refineries, which were placed in trust on October 9, 2001, as required by the US Federal Trade Commission, prior to disposition in February 2002.

⁴ ChevronTexaco is negotiating with the Panamanian government in order to cease refining operations and convert these facilities to terminal operations in 2002.

⁵ 1999 inputs include Koa Oil Co. Ltd. refineries. Interests sold in 1999.

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Petroleum – Refined Products Marketing

Product Sales: The company markets petroleum products throughout much of the world. The principal brands for identifying these products are “Chevron,” “Texaco” and “Caltex.”

The following table shows the company’s and its affiliates’ refined product sales volumes, excluding intercompany sales, over the past three years.

Refined Products Sales Volumes^1,2

(Thousands of Barrels Per Day)


		2001		2000		1999

United States
	Gasolines		1,246		1,320		1,266
	Jet Fuel		481		481		451
	Gas Oils and Kerosene		419		419		410
	Residual Fuel Oil		228		179		227
	Other Petroleum Products³		203		268		269

	Total United States		2,577		2,667		2,623

International
	Gasolines		410		455		481
	Jet Fuel		136		156		145
	Gas Oils and Kerosene		925		629		647
	Residual Fuel Oil		475		573		567
	Other Petroleum Products³		549		708		781

	Total International		2,495		2,521		2,621

Total Worldwide			5,072		5,188		5,244

¹ Includes equity in affiliates

² Includes Equilon and Motiva pre-merger

³ Principally naphtha, lubricants, asphalt and coke

In the United States, the company supplies, directly or through dealers and jobbers, more than 8,200 motor vehicle retail outlets, of which about 1,300 are company-owned or -leased stations. The company’s gasoline market area is concentrated in the southern, southwestern and western states. According to the Lundberg Share of Market Report, ChevronTexaco ranks among the top three gasoline marketers in 16 states. The company’s former affiliates, Equilon and Motiva, operated through approximately 22,000 retail outlets in the United States. ChevronTexaco sold its investments in Equilon and Motiva in February 2002.

In Canada – primarily British Columbia – the company’s branded products are sold in approximately 170 stations (mainly owned or leased).

ChevronTexaco operates a network of over 8,000 service stations and 650 convenience stores in more than 30 countries that cover the Asia-Pacific region, Southern and East Africa, and the Middle East. ChevronTexaco will continue to use the Caltex brand name in these areas.

In Europe, the company has marketing operations in the United Kingdom, Ireland, Netherlands, Belgium, Luxembourg and the Scandinavian countries. In West Africa, the company operates in Cameroon, the

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Canary Islands, Cote d’Ivoire, Nigeria, Togo and Benin. In these regions, the company mainly uses the Texaco brand name.

ChevronTexaco operates in approximately 40 countries across the Caribbean, Central America, and South America, with a significant presence in Brazil. In this region, the company uses the Texaco brand name.

In addition to the above activities, the company manages other marketing businesses globally. In global aviation fuel marketing, the company markets more than 400,000 barrels per day of aviation fuel in about 75 countries, representing a worldwide market share of about 12 percent. The company is the leading marketer of jet fuels in North America and ranks third in the Asia-Pacific region, Latin America, and the Caribbean. ChevronTexaco markets residual fuel oils and marine lubricants in over 100 countries, and motor lubricants in nearly 200 countries.


	Petroleum – Transportation

Pipelines: ChevronTexaco owns and operates an extensive system of crude oil, refined products, chemicals, natural gas liquids and natural gas pipelines in the United States. The company also has direct or indirect interests in other U.S. and international pipelines. The company’s ownership interests in pipelines are summarized in the following table:

Pipeline Mileage At December 31, 2001


		Wholly		Partially
		Owned		Owned¹		Total

United States:
	Crude oil²		1,876		458		2,334
	Natural gas		1,403		1,872		3,275
	Petroleum products		3,624		1,869		5,493

	Total United States		6,903		4,199		11,102

International:
	Crude oil²		—		694		694
	Natural gas		—		184		184
	Petroleum products		4		547		551

	Total International		4		1,425		1,429

Worldwide			6,907		5,624		12,531


¹	Reflects equity interest in pipelines, except for those owned by Dynegy Inc.

²	Includes gathering lines related to the transportation function. Excludes gathering lines related to the U.S. and international production activities.

The Caspian Pipeline Consortium (CPC) was formed to build a crude oil export pipeline from the Tengiz Field to the Russian Black Sea port of Novorossiysk. The company has a 15 percent ownership interest in CPC. The first delivery of Tengizchevroil crude oil from the CPC terminal occurred in October 2001. When the construction project, including the pipeline, pump stations and terminal, is essentially complete, by the second quarter of 2002, the CPC system capacity will be 600,000 barrels of oil per day. Additional capacity will be possible with additional pump stations and tankage.

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Tankers: ChevronTexaco’s controlled seagoing fleet at December 31, 2001, is summarized in the following table. All controlled tankers were utilized in 2001. In addition, at any given time, the company has 30 to 40 vessels under charter on a term or voyage basis.

Controlled Tankers At December 31, 2001



		U.S. Flag				Foreign Flag

				Cargo Capacity				Cargo Capacity
		Number		(Millions of Barrels)		Number		(Millions of Barrels)

Owned			3		0.8		8		10.4
Bareboat Charter			—		—		15		21.2
Time-Charter			—		—		4		2.2

	Total		3		0.8		27		33.8

Federal law requires that cargo transported between U.S. ports be carried in ships built and registered in the United States, owned and operated by U.S. entities and manned by U.S. crews. At year-end 2001, the company’s U.S. flag fleet was engaged primarily in transporting crude oil from Alaska to refineries on the West Coast and Hawaii, refined products between the Gulf Coast and East Coast, and refined products from California refineries to terminals on the West Coast, Alaska and Hawaii.

The Federal Oil Pollution Act of 1990 requires the scheduled phase-out, by year-end 2010, of all single hull tankers trading to U.S. ports or transferring cargo in waters within the U.S. Exclusive Economic Zone. This has resulted in the utilization of more costly double-hull tankers. By the end of 2001, ChevronTexaco was operating a total of 16 double-hull tankers. ChevronTexaco expects to take delivery of two additional double-hull tankers in 2003, also to be operated under long-term bareboat charters. The company is a member of many oil-spill response cooperatives in areas in which it operates around the world.

At year-end 2001, two of the company’s controlled international flag vessels continued to be used as floating storage vessels in its upstream operations offshore Cabinda Province, Angola. The remaining international flag vessels were engaged primarily in transporting crude oil from the Middle East, Indonesia, Mexico and West Africa to ports in the United States, Europe, and Asia. Refined products also were transported by tanker worldwide.

Energy Marketing and Services – Dynegy

ChevronTexaco owns an approximate 26 percent equity share of Dynegy Inc. (Dynegy), which is one of the world’s leading energy merchants. Dynegy reported record net income of $648 million in 2001, a 29 percent increase compared with 2000. ChevronTexaco invested a total of $1.7 billion in Dynegy in 2001 and January 2002. Dynegy’s equity market value at December 31, 2001, was $8.6 billion. Through a global physical network of assets and marketing, logistics and risk management capabilities, Dynegy provides energy and communications solutions to customers in North America, the United Kingdom and continental Europe. Dynegy’s activity extends across the entire convergence value chain, from power generation, wholesale and direct commercial and industrial marketing and trading of power, natural gas, coal, emission allowances, weather derivatives, and broadband to transportation, gathering and processing of natural gas liquids.

Dynegy is one of the leading natural gas marketers in North America, with sales of more than 13 billion cubic feet per day, and a leading natural gas liquids marketer, with worldwide sales in excess of 557,000 barrels per day. Dynegy is also one of the largest processors of natural gas in North America, with production of more than 84,000 barrels of natural gas liquids per day. As of January 1, 2002, Dynegy

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operates or controls 19,100 gross megawatts of power generation capacity and plans to add over 1,400 gross megawatts in 2002.

Dynegy and ChevronTexaco formed a long-term strategic alliance in 1996 whereby Dynegy purchases essentially all natural gas and natural gas liquids produced or controlled by the legacy Chevron operations in the United States (excluding Alaska) and supplies natural gas and natural gas liquids feedstocks to most of ChevronTexaco’s U.S. refineries and chemical plants. In March 2002, the company reached agreement with Dynegy to expand those contracts to include substantially all of legacy Texaco’s undedicated U.S. natural gas and natural gas liquids production.


	Chemicals

Chevron Phillips Chemical Company (CPChem) is a 50-50 joint venture with Phillips Petroleum Company formed in July 2000, when both companies combined most of their petrochemicals operations. CPChem owns or has joint venture interests in 34 manufacturing facilities and five research and technical centers in the United States, Puerto Rico, Belgium, China, Mexico, Saudi Arabia, Singapore, and South Korea.

In December 2001, commercial production of K-Resin resumed with the completion of Phase I of the rebuild at the Houston Chemical Complex, shut down since an explosion and fire that occurred in March 2000. Restoration of the remaining K-Resin capacity will be completed in 2002, bringing annual production capacity to 335 million pounds.

An olefins and polyolefins complex in Qatar is under construction and expected to start production in late 2002. Annual production capabilities at the complex include 1.1 billion pounds of ethylene, 1 billion pounds of polyethylene, and 100 million pounds of hexene-1. The complex is owned and will be operated by Qatar Chemical Company, Ltd. a joint venture between CPChem, with a 49 percent interest, and Qatar General Petroleum, which owns the remaining 51 percent.

A 50-50 joint venture with BP Solvay to build a new high-density polyethylene (HDPE) facility at a CPChem site in the Houston area is on track for start-up in late 2002. The jointly owned 700-million-pounds-per-year HDPE facility will be the largest of its kind in the world and will use CPChem proprietary manufacturing technology.

ChevronTexaco retained its “Oronite” fuel and lubricant additives business. Oronite is a leading developer, manufacturer and marketer of performance additives for fuels and lubricating oils. The company owns and operates five manufacturing facilities in the United States, France, Singapore, Japan and Brazil and has equity interests in facilities in India and Mexico.


	Coal

The company’s coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), owned and operated two surface mines and one underground mine at year-end 2001. P&M also owns an approximate 30 percent interest in Inter-American Coal Holding N.V., which has interests in mining operations in Venezuela.

Sales and other operating revenues in 2001 were $353 million, an increase of 19 percent from 2000. Sales of coal from P&M’s wholly owned mines and from its affiliates were 16.2 million tons, an increase of 17 percent from 2000. At year-end 2001, P&M controlled approximately 196 million tons of developed and undeveloped coal reserves, including significant reserves of environmentally desirable low-sulfur fuel.


	Other Activities – Synthetic Crude Oil

In Canada, ChevronTexaco has a 20 percent interest in the Athabasca Oil Sands Project. The project is expected to begin bitumen production in late 2002 and reach 155,000 barrels of bitumen per day at peak production. The bitumen will be upgraded into high quality synthetic oil using hydroprocessing technology at a synthetic crude unit, which will start up by late 2002 or early 2003.

—19—


	Power and Gasification

ChevronTexaco participates in its power and gasification business through ownership, equity investments with others and licensing of proprietary technology. The company’s electrical power business includes conventional power generation projects, as well as cogeneration facilities. Cogeneration produces thermal energy, such as steam, and electric power. ChevronTexaco has used steam produced in cogeneration in its upstream operations in onshore California and Indonesia. ChevronTexaco uses its proprietary gasification technology to convert a wide variety of hydrocarbon feedstocks into a clean synthesis gas. The synthetic gas can be used to generate electricity in low-emission power plants. ChevronTexaco licenses this technology, operates owned gasification facilities and invests in projects using the technology. With licenses and partners, the company has interests in over 70 gasification facilities operating or being developed worldwide.


	Research and Technology

The company’s core hydrocarbon technology efforts support the upstream, downstream and power and gasification businesses, aimed at developing and applying these technologies to create increased value. These activities include heavy oil recovery and upgrading, deepwater exploration and production, shallow water production operations, gas-to-liquids processing, hydrocarbon gasification to power, and new and improved refinery processes.

Additionally, ChevronTexaco’s Technology Ventures Company focuses upon the identification, growth, and commercialization of emerging technologies for new energy applications. The range of business spans early-stage venture capital investing in emerging technologies to developing joint venture companies in new energy systems such as advanced batteries for distributed power and transportation systems, fuel cells and hydrogen fuel storage.

The company is building an information technology infrastructure encompassing computing, data management, security, and connectivity of partners, suppliers, and employees. The architecture, known as “Net Ready,” is designed to provide the foundation for the company to rapidly integrate advances in computing and network-based technology.

ChevronTexaco’s research and development expenses were $209 million, $211 million and $226 million for the years 2001, 2000 and 1999, respectively.

Because some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, ultimate success is not always certain. Although not all initiatives may prove to be economically viable, the company’s overall investment in this area is not significant to the company’s consolidated financial position.


	Environmental Protection

Virtually all aspects of the company’s businesses are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to change and increase in both number and complexity, and govern not only the manner in which the company conducts its operations, but also the products it sells. ChevronTexaco expects more environmental-related regulations in the countries where it has operations. Most of the costs of complying with the myriad laws and regulations pertaining to its operations are embedded in the normal costs of conducting its business.

In 2001, the company’s U.S. capitalized environmental expenditures were $220 million, representing approximately 4 percent of the company’s total consolidated U.S. capital and exploratory expenditures. These environmental expenditures include capital outlays to retrofit existing facilities, as well as those associated with new facilities. The expenditures are predominantly in the petroleum segment and relate mostly to air and water quality projects and activities at the company’s refineries, oil and gas producing facilities and marketing facilities. For 2002, the company estimates U.S. capital expenditures for environmental control facilities will be $370 million. The future annual capital costs of fulfilling this

—20—

commitment are uncertain and will be governed by several factors, including future changes to regulatory requirements.

Further information on environmental matters and their impact on ChevronTexaco, and the company’s 2001 environmental expenditures, remediation provisions and year-end environmental reserves are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages FS-10 and FS-11 of this Annual Report on Form 10-K.

Item 2. Properties

The location and character of the company’s oil, natural gas and coal properties and its refining, marketing, transportation and chemicals facilities are described above under Item 1. Business. Information required by the Securities Exchange Act Industry Guide No. 2 (“Disclosure of Oil and Gas Operations”) is also contained in Item 1 and in Tables I through VII on pages FS-45 to FS-51 of this Annual Report on Form 10-K. Note 15, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-33 of this Annual Report on Form 10-K.

Item 3. Legal Proceedings

A. Texaco Exploration and Production Inc. – Aneth Producing Unit and Gas Plant – Clean Air Act Enforcement Action

Texaco Exploration and Production Inc. (“TEPI”) has agreed to pay a civil penalty of $243,725 to settle an enforcement action brought by the United States Environmental Protection Agency involving alleged Clean Air Act violations at TEPI’s Aneth Producing Unit and Gas Plant, located on the Navajo Nation in Utah. In addition, TEPI has agreed to a supplemental environmental project wherein it will provide a local fire department in Montezuma Creek, Utah with $51,275 in emergency response equipment and hazardous materials training. The alleged violations include: 1) a claim that TEPI’s Aneth Producing Unit failed to provide notice to emergency response authorities of releases of sulfur dioxide in December 1997 as required by section 304 of the Emergency Planning and Community Right-to-Know Act; and 2) non-compliance with Clean Air Act regulations at the Aneth Gas Plant near Montezuma Creek, Utah, resulting from a 1991 renovation of the facility and the cleanup of asbestos-containing materials following a 1997 explosion.

B. Texaco Exploration and Production Inc. – Aneth Producing Unit – Clean Water Act Enforcement Action

Texaco Exploration and Production Inc. (“TEPI”) has agreed to a civil penalty of $370,000 to settle an enforcement action brought by the United States Environmental Protection Agency involving alleged Clean Water Act violations at TEPI’s Aneth Producing Unit located on the Navajo Nation in Utah. In addition to the civil penalty, TEPI agreed to fund a $479,000 supplemental environmental project. The alleged violations include: 1) a claim that TEPI did not report releases of pollutants as required by law and 2) unlawful releases of pollutants into Waters of the United States.

C. Texaco Chemical Company – Clean Water Act Enforcement Action

Texaco Chemical Company (“TCC”) has agreed to pay a $300,000 civil penalty to settle an administrative enforcement action initiated by the United States Environmental Protection Agency. This enforcement action, which involved two separate proceedings initiated in 1992 and subsequently consolidated, alleged violations of the Texas State Implementation Plan; hazardous waste laws; Polychlorinated Biphenyl (PCB) regulations; and release notification and requirements at the TCC facility located in Port Neches, Texas. The stock of TCC was sold to Huntsman in 1994 and ChevronTexaco has no current relationship with the Port Neches facility.

—21—

Item 4. Submission of Matters to a Vote of Security Holders

The following matters were submitted to a vote of Chevron Corporation stockholders at a special meeting on October 9, 2001.

Voters approved the issuance of common stock to Texaco Inc. stockholders at a ratio of 0.77 shares of ChevronTexaco common stock for each share of Texaco common stock, by a vote of 442,294,614 votes (98.9 percent) for and 4,754,183 (1.1 percent) against. There were 4,926,109 abstentions.

Voters approved the amendment of the Restated Certificate of Incorporation to change the name of Chevron Corporation to “ChevronTexaco Corporation,” by a vote of 438,925,583 votes (97.9 percent) for and 9,456,781 (2.1 percent) against. There were 3,594,154 abstentions.

Executive Officers of the Registrant at March 1, 2002


Name and Age		Executive Office Held	Major Area of Responsibility

D. J. O’Reilly	55	Chairman of the Board since 2000 Director since 1998 Vice-Chairman from 1998 to 2000 President of Chevron Products Company from 1994 to 1998 Executive Committee Member since 1994		Chief Executive Officer

P. J. Robertson	55	Vice-Chairman of the Board since 2002 Vice-President since 1994 President of Chevron Overseas Petroleum Inc. from 2000 to 2002 Executive Committee Member since 1997	Office of the Chairman Worldwide Exploration and Production Activities

G. F. Tilton	53	Vice-Chairman of the Board since 2001 Director since 2001 Chairman of the Board and Chief Executive Officer, Texaco Inc., 2001 President of Global Business Unit, Texaco Inc. from 1997 to 2001 Executive Committee Member since 2001		Office of the Chairman

D. W. Callahan	59	Executive Vice-President since 2000 Vice-President since 1999 President of Chevron Chemical Company from 1999 to 2000 Executive Committee Member since 1999	Chemicals, Coal, Human Resources, Technology

H. D. Hinman	61	Vice-President and General Counsel since 1993 Executive Committee Member since 1993		Law

G. L. Kirkland	51	President of ChevronTexaco Overseas Petroleum Inc. since 2002 Vice-President since 2002 President of Chevron U.S.A. Production Company from 2000 to 2002 Executive Committee Member from 2000 to 2001	Overseas Exploration and Production

J. S. Watson	45	Vice-President and Chief Financial Officer since 2000 Vice-President since 1998 Executive Committee Member since 2000		Finance

—22—

Executive Officers of the Registrant at March 1, 2002 — (continued)


Name and Age		Executive Office Held	Major Area of Responsibility


R. I. Wilcox	56	President, North America Exploration and Production since 2002 Vice President since 2002	North American Exploration and Production

P. A. Woertz	48	Executive Vice President since 2001 Vice-President since 1998 President of Chevron Products Company From 1998 to 2001 Executive Committee Member since 1998	Worldwide Refining, Marketing and Transportation Activities

The Executive Officers of the Corporation consist of the Chairman of the Board, the Vice-Chairman of the Board, and such other officers of the Corporation who are either Directors or members of the Executive Committee, or who are chief executive officers of principal business units. Except as noted below, all of the Corporation’s Executive Officers have held one or more of such positions for more than five years.


D. W. Callahan		- Senior Vice President, Chevron Chemical Company – 1991 - President, Chevron Chemical Company – 1999

G. L. Kirkland		- General Manager, Asset Management, Chevron Nigeria Limited – 1996 - Chairman and Managing Director, Chevron Nigeria Limited – 1996 - President, Chevron USA Production Company – 2000

P. J. Robertson		- Executive Vice-President of Chevron U.S.A. Production Company – 1996 - Vice-President, Chevron Corporation and President of Chevron U.S.A. Production Company – 1997 - President of Chevron Overseas Petroleum Inc. since 2000

G. F. Tilton		- President of Texaco USA – 1995 - President of Global Businesses, Texaco Inc. – 1997

J. S. Watson		- President, Chevron Canada Limited – 1996 - Vice-President, Strategic Planning, Chevron Corporation – 1998 - Vice-President and Chief Financial Officer, Chevron Corporation – 2000

R. I. Wilcox		- Vice President and General Manager, Marine Transportation, Chevron Shipping Company – 1996 - General Manager, Asset Management, Chevron Nigeria Limited – 1999 - Chairman and Managing Director, Chevron Nigeria Limited – 2000 - Corporate Vice President and President, North America Exploration and Production – 2002

P. A. Woertz		- President, Chevron International Oil Company – 1996 - Vice President, Logistics and Trading, Chevron Products Company – 1996 - President, Chevron Products Company – 1998

PART II

Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters

The information on ChevronTexaco’s common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-43 of this Annual Report on Form 10-K.

—23—

Item 6. Selected Financial Data

The selected financial data for years 1997 through 2001 are presented on page FS-44 of this Annual Report on Form 10-K.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1 of this Annual Report on Form 10-K.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The company’s discussion of interest rate, foreign currency and commodity price market risk is contained on pages FS-9 and FS-10. Management’s Discussion and Analysis of Financial Condition and Results of Operations – “Financial Instruments” and Note 10 to the Consolidated Financial Statements – “Financial and Derivative Instruments” beginning on page FS-27.

Item 8. Financial Statements and Supplementary Data

The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1 of this Annual Report on Form 10-K.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

PART III

Item 10. Directors and Executive Officers of the Registrant

The information on Directors appearing under the heading “Nominees For Directors” in the Notice of the 2002 Annual Meeting of Stockholders and 2002 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, as amended, in connection with the company’s 2002 Annual Meeting of Stockholders, is incorporated herein by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 22 and 23 of this Annual Report on Form 10-K for information about Executive Officers of the company.

The information contained under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in the Notice of the 2002 Annual Meeting of Stockholders and 2002 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, as amended, in connection with the company’s 2002 Annual Meeting of Stockholders, is incorporated herein by reference in this Annual Report on Form 10-K. ChevronTexaco believes all filing requirements were complied with during 2001.

Item 11. Executive Compensation

The information appearing under the heading “Executive Compensation,” including the subheadings “Summary Compensation Table,” “Long-Term Incentive Plan – 2001 Performance Units Awards Table,” “Option Grants in Last Fiscal Year Table,” “G. F. Tilton’s Option Grants in Last Fiscal Year Table,” “Aggregated Option Exercises in Last Fiscal Year and Fiscal Year-end Option Values Table,” “Pension Plan Table,” “Termination of Employment and Change-in-Control Arrangements” and “Summary of Glenn F. Tilton’s Employment Agreement” and in the Notice of the 2002 Annual Meeting of Stockholders and 2002 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, as amended, in connection with the company’s 2002 Annual Meeting of Stockholders, is incorporated herein by reference in this Annual Report on Form 10-K.

—24—

Item 12. Security Ownership of Certain Beneficial Owners and Management

The information appearing under the heading “Directors’ and Executive Officers’ Stock Ownership” in the Notice of the 2002 Annual Meeting of Stockholders and 2002 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, as amended, in connection with the company’s 2002 Annual Meeting of Stockholders, is incorporated herein by reference in this Annual Report on Form 10-K.

Item 13. Certain Relationships and Related Transactions

The information appearing under the heading “Transactions with Directors and Officers” in the Notice of the 2002 Annual Meeting of Stockholders and 2002 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, as amended, in connection with the company’s 2002 Annual Meeting of Stockholders, is incorporated herein by reference in this Annual Report on Form 10-K.

PART IV

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

(a) The following documents are filed as part of this report:

(1) Financial Statements:


	Page(s)

Report of Independent Accountants – PricewaterhouseCoopers LLP		FS-15
Report of Independent Public Accountants – Arthur Andersen LLP		FS-15
Consolidated Statement of Income for the three years ended December 31, 2001		FS-16
Consolidated Statement of Comprehensive Income for the three years ended December 31, 2001		FS-17
Consolidated Balance Sheet at December 31, 2001 and 2000		FS-18
Consolidated Statement of Cash Flows for the three years ended December 31, 2001		FS-19
Consolidated Statement of Stockholders’ Equity for the three years ended December 31, 2001		FS-20 to FS-21
Notes to Consolidated Financial Statements		FS-22 to FS-42

(2) Financial Statement Schedules:

We have included on page 26 of this Annual report on Form 10-K, Financial Statement Schedule II – Valuation and Qualifying Accounts.

(3) Exhibits:

The Exhibit Index on pages E-1 and E-2 of this Annual Report on Form 10-K lists the exhibits that are filed as part of this report.

(b) Reports on Form 8-K:

(1) A Current Report on Form 8-K was filed by the company on November 19, 2001. In this report, ChevronTexaco filed the following financial information:

• Review of Operations 1998-2000

• Audited Supplemental Combined Financial Statements 1998-2000

• Supplemental Information on Oil and Gas Producing Activities 1998-2000

• Financial Summary 1996-2000

• Audited Schedule II – Valuation and Qualifying Accounts

—25—

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS ($ MILLIONS)



	Year ended December 31,

	2001			2000			1999

Employee Termination Benefits:
Balance at January 1	$	1		$	130		$	156
Additions charged to expense		763			15			291
Payments		(105	)		(144	)		(317	)

Balance at December 31*	$	659		$	1		$	130

*$275 is reported as “Deferred Credits and Other Noncurrent Obligations” on the Consolidated Balance Sheet

Other Merger-related Expenses:
Balance at January 1	$	—		$	—		$	—
Additions charged to expense		128			—			—
Payments		(1	)		—			—

Balance at December 31	$	127		$	—		$	—

Allowance for Doubtful Accounts:
Balance at January 1	$	136		$	113		$	90
Additions charged to expense		116			74			97
Bad debt write-offs		(69	)		(51	)		(74	)

Balance at December 31	$	183		$	136		$	113

Deferred Income Tax Valuation Allowance:*
Balance at January 1	$	1,574		$	1,588		$	1,295
Additions charged to deferred income tax expense		258			326			381
Deductions credited to deferred income tax expense		(401	)		(340	)		(88	)

Balance at December 31	$	1,431		$	1,574		$	1,588

*See also Note 16 to the consolidated financial statements on page FS-34

Inventory Valuation Allowance:
Balance at January 1	$	4		$	—		$	170
Additions		—			4			—
Deductions		(4	)		—			(170	)

Balance at December 31	$	—		$	4		$	—

—26—

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, on the 27th day of March 2002.

ChevronTexaco Corporation

By DAVID J. O’REILLY*

David J. O’Reilly, Chairman of the Board

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 27th day of March 2002.


Principal Executive Officers (And Directors)		Directors
DAVID J. O’REILLY* David J. O’Reilly, Chairman of the Board		SAMUEL H. ARMACOST* Samuel H. Armacost
PETER J. ROBERTSON* Peter J. Robertson, Vice-Chairman of the Board		ROBERT J. EATON* Robert J. Eaton
GLENN F. TILTON* Glenn F. Tilton, Vice-Chairman of the Board		SAM GINN* Sam Ginn
		CARLA A. HILLS* Carla A. Hills

Principal Financial Officer		FRANKLYN G. JENIFER* Franklyn G. Jenifer

JOHN S. WATSON* John S. Watson, Vice-President, Finance and Chief Financial Officer		J. BENNETT JOHNSTON* J. Bennett Johnston

Principal Accounting Officer		SAM NUNN* Sam Nunn
STEPHEN J. CROWE* Stephen J. Crowe, Vice-President and Comptroller		CHARLES R. SHOEMATE* Charles R. Shoemate
		FRANK A. SHRONTZ* Frank A. Shrontz
*By: /s/ LYDIA I. BEEBE Lydia I. Beebe, Attorney-in-Fact		THOMAS A. VANDERSLICE* Thomas A. Vanderslice
		CARL WARE* Carl Ware
		JOHN A. YOUNG* John A. Young

—27—

INDEX TO MANAGEMENT’S DISCUSSION AND ANALYSIS

CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


	Page(s)

Management’s Discussion and Analysis		FS-2 to FS-14
Report of Independent Accountants		FS-15
Report of Independent Public Accountants		FS-15
Consolidated Statement of Income		FS-16
Report of Management		FS-16
Consolidated Statement of Comprehensive Income		FS-17
Consolidated Balance Sheet		FS-18
Consolidated Statement of Cash Flows		FS-19
Consolidated Statement of Stockholders’ Equity		FS-20 to FS-21
Notes to Consolidated Financial Statements		FS-22 to FS-42
Quarterly Results and Stock Market Data		FS-43
Five-Year Financial Summary		FS-44
Supplemental Information on Oil and Gas Producing Activities		FS-44 to FS-51

FS-1

Management’s Discussion and Analysis of Financial Condition
and Results of Operations

TEXACO MERGER TRANSACTION
On October 9, 2001, Texaco Inc. (Texaco) became a wholly owned subsidiary of Chevron Corporation (Chevron) pursuant to a merger transaction, and Chevron changed its name to ChevronTexaco Corporation. The combination was accounted for as a pooling of interests, and each share of Texaco common stock was converted on a tax-free basis into the right to receive 0.77 shares of ChevronTexaco common stock. In the merger, ChevronTexaco issued approximately 425 million shares of common stock, representing about 40 percent of the outstanding ChevronTexaco common stock after the merger.

In accordance with pooling-of-interests accounting, the accompanying audited consolidated financial statements give retroactive effect to the merger, with all periods presented as if Chevron and Texaco had always been combined.

As a result of the merger, the accounts of certain operations that were jointly owned by the combining companies are consolidated in the accompanying financial statements. These operations are primarily those of the Caltex Group of Companies, which was previously owned 50 percent each by Chevron and Texaco.

KEY FINANCIAL RESULTS


Millions of dollars, except per-share amounts				2001			2000			1999

Net Income				$	3,288		$	7,727		$	3,247




Special Items and Merger Effects Included in Net Income					(3,522	)		(378	)		(191	)

Earnings Excluding Special Items and Merger Effects				$	6,810		$	8,105		$	3,438

Per Share:




	Net Income – Basic			$	3.10		$	7.23		$	3.01




		– Diluted		$	3.09		$	7.21		$	3.00




	Earnings Excluding Special Items and Merger Effects – Basic			$	6.42		$	7.58		$	3.19




			– Diluted	$	6.41		$	7.57		$	3.18




	Dividends*			$	2.65		$	2.60		$	2.48




Sales and Other Operating Revenues				$	104,409		$	117,095		$	84,004




Return on:




	Average Capital Employed				7.8	%		17.3	%		8.5	%




	Average Stockholders’ Equity				9.8	%		24.5	%		11.1	%

Chevron divided pre-merger.

ChevronTexaco’s net income of $3.288 billion was down significantly from 2000 but was slightly higher than 1999. Net income for 2001 included net charges of $1.743 billion for special items and $1.779 billion for merger effects, for a combined total of $3.522 billion. Special items included asset write-downs of $1.709 billion, primarily for exploration and production (upstream) properties as a result of downward revisions in estimated proved crude oil reserves. Merger effects represented merger-related expenses of $1.136 billion and net losses on merger-related asset dispositions of $643 million. In 2000 and 1999, net special charges were $378 million and $191 million, respectively.

Net income and special items for the individual business segments are discussed in the Results of Operations section beginning on page FS-4.

NET INCOME BY MAJOR OPERATING AREA¹


Millions of dollars		2001			2000			1999

Exploration and Production




	United States	$	1,779		$	3,453		$	1,133




	International		2,533			3,702			1,450

Total Exploration and Production			4,312			7,155			2,583

Refining, Marketing and Transportation




	United States		1,254			721			551




	International		560			414			546

Total Refining, Marketing and Transportation			1,814			1,135			1,097

Chemicals			(128	)		40			109




All Other			(2,710	)		(603	)		(542	)

Net Income²		$	3,288		$	7,727		$	3,247






¹ 1999 and 2000 conformed to the 2001 presentation




² Includes Foreign Currency Gains (Losses):		$	191		$	182		$	(15	)

EARNINGS BY MAJOR OPERATING AREA, EXCLUDING SPECIAL ITEMS AND
MERGER EFFECTS¹


Millions of dollars		2001			2000			1999

Exploration and Production




	United States	$	2,890		$	3,736		$	1,390




	International		2,905			3,622			1,520

Total Exploration and Production			5,795			7,358			2,910

Refining, Marketing and Transportation




	United States		1,332			974			638




	International		598			526			615

Total Refining, Marketing and Transportation			1,930			1,500			1,253

Chemicals			(32	)		130			174




All Other			(883	)		(883	)		(899	)

Earnings Excluding Special Items and Merger Effects²			6,810			8,105			3,438

Special Items and Merger Effects²			(3,522	)		(378	)		(191	)

Net Income²		$	3,288		$	7,727		$	3,247






¹ 1999 and 2000 conformed to the 2001 presentation




² Includes Foreign Currency Gains (Losses):		$	191		$	182		$	(15	)

BUSINESS ENVIRONMENT AND OUTLOOK
ChevronTexaco’s overall operating earnings depend largely on the profitability of its upstream – exploration and production – and downstream – refining, marketing and transportation – businesses.

Upstream operating earnings align most closely with industry price levels for crude oil and natural gas. The decline in the company’s upstream operating earnings during 2001 tracked the downward slide in prices for these commodities. The price trend for crude oil was largely caused by reduced demand in weakened economies worldwide and the relative oversupply by OPEC and certain other oil-producing countries.

FS-2

The average spot price during 2001 for West Texas Intermediate (WTI), a benchmark crude oil, was about $26 per barrel – down from an average of about $30 in 2000 – and ended the year under $20. A similar trend existed for certain natural gas prices, which are more sensitive to regional supply-demand balances. In the United States, the company’s average natural gas sales realization started 2001 at about $10.00 per thousand cubic feet. By the end of the year, the average realization had dropped below $3.00. Into early 2002, the WTI crude oil price moved above $20 per barrel, but the company’s U.S. average natural gas realization remained below $3.00 per thousand cubic feet. Earnings during 2001 were also dampened by slightly lower oil-equivalent production – down less than 2 percent from 2000 levels. However, the company anticipates an oil-equivalent production growth rate over the next five years of 2.5 to 3 percent annually, although 2002 production is expected to increase only about 1 percent because of OPEC-related constraints.

Downstream operating earnings are most closely tied to refining and marketing margins, which can vary among the geographic areas in which the company operates. Although world-wide demand for refined products weakened overall during 2001,margins fluctuated on regional supply-demand balances. For example, margins improved in North America over the prior year and sales volumes increased for all higher-value products. Margins also improved in most of the Asia, Middle East and eastern Africa operating areas. However, in Europe, Latin America and certain western African countries, changes in product prices were not able to keep pace with feedstock costs, and margins suffered. Early in 2002, profitability was weak in all geographic areas and is not expected to rebound in earnest until the world economies and product demand improve.

The company’s chemical segment was not profitable during 2001, and significant improvement for certain commodity chemicals is not expected until demand more closely matches industry capacity.

MERGER EFFECTS
Within 18 months of the merger, ChevronTexaco expects to realize pre-tax savings of approximately $1.8 billion annually through operating efficiencies and the elimination of redundant facilities and operations.

Significant one-time expenses are being incurred in connection with the merger. Total before-tax merger-related expenses, from the time of the merger announcement in October 2000 through the end of 2003, are estimated at $2 billion. Major expenses include employee severance payments; incremental pension and medical plan costs associated with work-force reductions; legal, accounting, SEC filing and investment banker fees; employee and office relocations; and costs for the elimination of redundant facilities and operations. During 2001, $1.563 billion of before-tax ($1.136 billion after tax) merger-related expenses were recorded. Included were accruals of $891 million for employee termination benefits for approximately 4,500 employees, and other merger-related expenses that will not benefit future operations. Payments against the accruals were $105 million. Approximately 1,400 employees were terminated after the merger during 2001. The year-end 2001 accrual balance of $786 million is expected to be nearly extinguished by early 2003, as certain terminating employees are eligible to delay separation payments for one year or more.

As a condition of approving the merger, the U.S. Federal Trade Commission (FTC) required the disposition of certain Texaco assets, including investments in Equilon and Motiva – joint ventures engaged in U.S. refining, marketing and transportation businesses. The interests in these joint ventures were placed in trust at the time of the merger, and ChevronTexaco no longer exercised control over the joint ventures. Accordingly, the method of accounting for these investments was changed in the fourth quarter 2001 from equity to cost basis. Based on the terms of the sale that closed in February 2002, the company recorded an after-tax charge of $564 million in 2001 for the anticipated loss. Cash proceeds from the sale received in 2002 were $2.2 billion. Indemnification by ChevronTexaco against certain Equilon and Motiva contingent liabilities at the date of sale are discussed in the “On- and off-balance-sheet arrangements” section on page FS-8.

Additional after-tax charges of $79 million were recorded in 2001 for other merger-related asset dispositions, which are expected to result in proceeds of approximately $75 million. Including the loss for the Equilon and Motiva sale, total charges for merger-related asset dispositions of $643 million were recorded in 2001 and classified as an “Extraordinary item” on the Consolidated Statement of Income in accordance with pooling-of-interests reporting requirements of Accounting Principles Board (APB) Opinion No. 16, “Business Combinations.” The net book value of these asset sales that were not completed at year-end 2001 was $2.181 billion and was classified as “Assets held for sale – merger related” in the “Current Assets” section of the Consolidated Balance Sheet. Net income during 2001 for all merger-related assets that are being sold was approximately $375 million.

OPERATING HIGHLIGHTS AND DEVELOPMENTS
Key operating highlights and events during 2001 and early 2002 included:

Worldwide oil and gas reserves The company added approximately 1.2 billion barrels of oil-equivalent reserves during 2001. These additions equated to 127 percent of production for the year. Included were slightly more than 100 million barrels each for the Tengiz Field in Kazakhstan and the Hamaca project in Venezuela as a result of drilling activities. Almost 200 million oil-equivalent barrels were added for natural gas reserves for several fields in Nigeria. About 160 million barrels of the additions during the year were the result of successful discoveries in areas that included Latin America, the North Sea and West Africa. Also, approximately 175 million equivalent-barrels were acquired early in 2001 through the purchase of an additional 5 percent interest in Tengizchevroil, the company’s 50 percent-owned affiliate in Kazakhstan that operates the Tengiz and Korolev fields.

Angola Approximately 30,000 barrels per day of total crude oil production began at the company-operated Phase 1C development in the deepwater Kuito Field in Block 14, where the company holds a 31 percent interest. In Block 0, the North Nemba production and gas injection platform was installed in March 2001. At year-end, total oil production exceeded 30,000 barrels per day. Continuation of the North Nemba development program in 2002 will result in average production of about 40,000 barrels per day. The company is the operator and holds a 39 percent interest.

FS-3

Nigeria The Escravos Gas Project successfully completed Phase 2 development in 2001, increasing processing capacity to 285 million cubic feet of gas per day. Upon completion of Phase 3 in 2005,capacity is expected to increase to 680 million cubic feet per day. The company holds a 40 percent working interest in the Escravos project. Front-end engineering and design started in March 2001 on the gas-to-liquids project at Escravos. This is the first project to use the Sasol Chevron Global Joint Venture technologies. The company holds a 38 percent interest in the project.

Chad-Cameroon The Doba oil field development — a $3.5 billion project, including a 650-mile pipeline — reached one-third completion at the end of 2001. Initial total production of 225,000 barrels of crude oil per day is expected in 2004. The company holds a 25 percent interest in the project.

Kazakhstan Tengizchevroil (TCO) increased its total production for the eighth straight year, averaging 268,000 barrels per day of crude oil. Engineering for the next major expansion is under way and it is expected to come on line in 2005. The company holds a 50 percent interest in TCO. In October, the first tankers were loaded with crude oil from the Caspian Pipeline Consortium (CPC) facilities near the Black Sea port of Novorossiysk. CPC’s pipeline connects the Tengiz Field in western Kazakhstan to Novorossiysk, enabling full access to world market prices for Tengiz oil, and greatly reduces transportation costs. CPC is owned 15 percent by ChevronTexaco.

U.K. North Sea In December 2001, ChevronTexaco received government approval to develop the company-operated Alba Extreme South and Caledonia projects in the North Sea. Both are located in the company’s central North Sea core area, which includes the producing Alba and Britannia fields. frFirst oil production from the Alba Extreme South project is scheduled for the fourth quarter 2002 and will help maintain Alba’s total field production at about 80,000 barrels of crude oil per day. Chevron-Texaco operates the field and holds a 21 percent ownership. First oil from Caledonia is expected late in the third quarter of 2002, and peak field production is anticipated at about 13,000 barrels per day. The company holds a 27 percent interest.

Philippines Gas production commenced in October from the Malampaya Field offshore the Philippine island of Palawan. ChevronTexaco has a 45 percent interest in the landmark gas-to-power project – the largest single foreign investment and the first-ever offshore production of natural gas in the Philippines.

Australia The company made two significant natural gas discoveries offshore Western Australia. Both are located in permit area WA-267-P, where the company operates and holds a 50 percent interest. During 2001, the company approved development of the $1.6 billion LNG expansion project by the North West Shelf venture. A mid-2004 start-up will increase gross liquefied natural gas capacity by about 50 percent. The company holds a one-sixth interest.

China During 2001, an average of about 18,000 barrels per day total of low-sulfur crude oil is being produced after an October start-up at the QHD 32-6 Field in China’s Bohai Bay where ChevronTexaco holds a 24.5 percent interest.

Bangladesh In April 2001, ChevronTexaco was awarded a 60 percent interest in the 1.7 million-acre onshore tract, Block 9, in Bangladesh, east of Dhaka. Block 9 surrounds the Bakhrabad gas field and is adjacent to other major gas-producing areas. Seismic studies are planned in 2002 with initial drilling to commence in late 2002 or early 2003.

Venezuela The company holds a 30 percent interest in the Hamaca integrated oil project, located in Venezuela’s Orinoco Belt. Early production was established during October 2001.After completion of crude oil upgrading facilities in 2004, Hamaca total production is expected to increase to 190,000 barrels per day.

U.S. Gulf of Mexico Typhoon, a deepwater development project, was completed below budget and production commenced in July 2001, two months ahead of schedule. Daily total production averaged about 39,000 oil-equivalent barrels through the end of the year. ChevronTexaco is the operator with a 50 percent interest.

U.S. Refining In December, the company approved a $150 million project at its Pascagoula, Mississippi, refinery to produce low-sulfur gasoline that meets anticipated new U.S. Environmental Protection Agency standards. Regulatory permits have been secured and the activities will commence during 2002. The project is expected to take a year to complete.

Chevron Phillips Chemical Company (CPChem) The company’s 50 percent-owned CPChem affiliate is engaged in a joint venture with BP Solvay to build a new high-density polyethylene (HDPE) facility at CPChem’s Cedar Bayou, Texas, facility that is on track for a start-up in late 2002. The 700 million pounds-per-year HDPE facility will be the largest of its kind in the world. A world-scale olefins and polyolefins complex in Qatar also is expected to start production in late 2002. The facility will be owned and operated by Qatar Chemical Company, a joint venture between CPChem, with a 49 percent interest, and Qatar General Petroleum.

Dynegy Inc. In November 2001, ChevronTexaco acquired $1.5 billion in redeemable, convertible preferred shares of its Dynegy affiliate. In early 2002, ChevronTexaco purchased approximately $200 million of additional Dynegy common shares to maintain its 26.5 percent ownership interest following Dynegy’s public equity offering in December 2001.

RESULTS OF OPERATIONS
Sales and other operating revenues were $104 billion in 2001, compared with $117 billion in 2000 and $84 billion in 1999. Revenues in 2001 declined on lower average realizations for crude oil and refined products. The increase in 2000 from 1999 was primarily the result of sharply higher prices for crude oil, natural gas and refined products. The effect of higher prices in 2000 was partially offset by the absence of chemicals revenues in the second half of the year due to the July 1, 2000, formation of CPChem, which is accounted for under the equity method.

Income from equity affiliates totaled $1.1 billion in 2001, $1.1 billion in 2000 and $0.9 billion in 1999. Equity income increased marginally in 2001 on the strength of improved earnings for Equilon, Motiva and Dynegy, partially offset by lower earnings for Tengizchevroil and LG-Caltex and by larger losses from CPChem. In 2000, increases in earnings from Tengiz-chevroil and Motiva were partially offset by lower earnings from Equilon and LG-Caltex and losses from CPChem.

Other income totaled $0.7 billion in 2001, $1.0 billion in 2000 and $0.8 billion in 1999. The fluctuations between years were the result of changes in net gains and losses from asset sales and interest income from investments.

FS-4

Purchased crude oil and products costs of $60.5 billion in 2001 were lower than the $69.8 billion in 2000 – primarily due to lower crude oil prices – but about 30 percent higher than the $46.3 billion in 1999 when average crude oil prices were recovering from 20-year lows that occurred in 1998. Offsetting some of the effect of higher prices since 1999 was the absence of such costs associated with the chemicals operations contributed to CPChem in July 2000.

Operating, selling, general and administrative expenses, excluding the effects of special items, were about the same at $11.5 billion in 2001 and 2000. Similar expenses in 1999 were $10.8 billion, reflecting mainly higher fuel costs for the company’s plants and facilities. Mitigating this effect since mid-2000 was the absence of expenses associated with the chemicals operations contributed to CPChem.


Millions of dollars		2001		2000		1999

Operating Expenses		$	7,650	$	8,323	$	7,773




Selling, General and Administrative Expenses			3,984		3,626		3,222

Total Operating Expenses			11,634		11,949		10,995




	Less: Special Charges, Before Tax		164		488		199

Adjusted Total Operating Expenses		$	11,470	$	11,461	$	10,796

Exploration expenses were $1.0 billion in 2001, compared with $0.9 billion in 2000 and $1.1 billion in 1999. In 2001, well write-offs were $184 million higher compared with 2000 – which more than offset declines in other exploration expenses. The increased write-offs reflected, in part, a reprioritization of development opportunities post-merger.

Depreciation, depletion and amortization expense was $7.1 billion in 2001, compared with $5.3 billion in 2000 and $4.9 billion in 1999. Depreciation expense associated with asset impairments was $2.3 billion in 2001, compared with $0.7 billion in 2000 and $0.4 billion in 1999. After adjusting for the effect of impairments, the expense amounts were $4.8 billion in 2001, $4.6 billion in 2000 and $4.5 billion in 1999. Higher expense in 2001 on this adjusted basis resulted from higher capital spending, reserve revisions and additional abandonment provisions, while 2000 was higher than 1999 because production between years increased. The expense in 2000 also reflected lower depreciation in chemicals, resulting from the CPChem joint venture formation.

Income tax expenses were $4.4 billion in 2001, $6.3 billion in 2000 and $2.6 billion in 1999, reflecting effective income tax rates of 53 percent, 45 percent and 44 percent for each of the three years, respectively.

The increase in the 2001 effective tax rate was primarily due to U.S. before-tax income (generally subject to a lower tax rate) being a significantly smaller percentage of overall before-tax income in 2001 compared with 2000. The decline in the U.S. before-tax income arose primarily because substantially all of the 2001 merger-related expenses were associated with operations in the United States.

Foreign currency gains in 2001 were $191 million, compared with gains of $182 million in 2000 and losses of $15 million in 1999. Approximately $150 million of the gains in 2001 were attributable to the devaluation of the Argentine peso late in the year. Excluding this impact, currency gains were lower than in 2000 primarily due to fluctuations of the Netherlands and Australian currencies. The losses in 1999 were primarily in Australia.

U.S. Exploration and Production


Millions of dollars		2001			2000			1999

Earnings Excluding Special Items		$	2,890		$	3,736		$	1,390

	Asset Write-Offs and Revaluations		(1,168	)		(176	)		(204	)




	Asset Dispositions		49			(107	)		–




	Prior-Year Tax Adjustments		8			–			–




	Restructurings and Reorganizations		–			–			(53	)

Total Special Items			(1,111	)		(283	)		(257	)

Segment Income		$	1,779		$	3,453		$	1,133

U.S. exploration and production earnings, excluding special items, declined in 2001 primarily because of significantly lower crude oil prices. Oil-equivalent production was also down 8 percent. Higher earnings in 2000, compared with 1999, were mainly the result of increased prices for crude oil and natural gas. Partially offsetting the benefit of higher prices was a decline in oil-equivalent production of 7 percent between years.

The company’s average 2001 U.S. crude oil realization was $21.70 per barrel, compared with $26.69 in 2000 and $15.50 in 1999. The average U.S. natural gas realization was $4.38 per thousand cubic feet in 2001, compared with $3.87 and $2.12 in 2000 and 1999, respectively.

Net liquids production for 2001 averaged 614,000 barrels per day, down 8 percent from 2000 and 14 percent from 1999. Net natural gas production averaged 2.7 billion cubic feet per day in 2000,down 7 percent from 2000 and 14 percent from 1999. The lower oil-equivalent production reflected normal field declines and asset sales, partially offset by new and enhanced production in the deep water and other areas of the Gulf of Mexico.

Special items in 2001 included a $1.0 billion impairment of the Midway Sunset Field in California’s San Joaquin Valley. The impairment was a result of the write-down in proved crude oil reserve quantities, upon determination of lower-than-projected oil recovery from the field’s steam injection process.

International Exploration and Production


Millions of dollars		2001			2000		1999

Earnings Excluding Special Items*		$	2,905		$	3,622	$	1,520

	Asset Write-Offs and Revaluations		(247	)		–		–




	Asset Dispositions–					80		–




	Prior-Year Tax Adjustments		(125	)		–		(47	)




	Restructurings and Reorganizations		–			–		(23	)

Total Special Items			(372	)		80		(70	)

Segment Income*		$	2,533		$	3,702	$	1,450






*Includes Foreign Currency Gains:		$	181		$	97	$	9

International exploration and production earnings, excluding special items, declined in 2001 primarily on lower average crude oil prices. Partially offsetting this effect was an increase of about 3 percent in oil-equivalent production and higher natural gas prices. Earnings in 2000 improved from 1999 on significantly higher crude oil and natural gas prices; oil-equivalent production between years was flat.

FS-5

The average liquids realization, including equity affiliates, was $22.17 per barrel in 2001, compared with $26.04 in 2000 and $16.57 in 1999. The average natural gas realization was $2.36 per thousand cubic feet in 2001, compared with $2.09 in 2000 and $1.66 in 1999.

Daily net liquids production of 1.345 million barrels in 2001 increased about 1 percent from 1.330 million barrels in 2000 and 1.337 million barrels in 1999. Production increases in Kazakhstan during 2001 more than offset lower volumes from Indonesia. In 2000, increases in Argentina, Kazakhstan, Kuwait and Thailand did not offset declines in Indonesia and the United Kingdom.

Net natural gas production of 1.711 billion cubic feet per day in 2001 was up 10 percent from 2000 and more than 13 percent from 1999. Most notable among the geographic areas with production increases were Kazakhstan, Trinidad and Canada. In 2000, production increases were primarily in Argentina, Colombia, Kazakhstan and Thailand, partially offset by lower production from normal declines in mature fields in Canada and the United Kingdom.

Special items in 2001 included a $247 million impairment of the LL-652 Field in Venezuela – as slower-than-expected reservoir repressurization resulted in a reduction in the projected volumes of oil recoverable during the company’s remaining contract period of operation.

U.S. Refining, Marketing and Transportation


Millions of dollars		2001			2000			1999

Earnings Excluding Special Items		$	1,332		$	974		$	638

	Asset Write-Offs and Revaluations		–			–			(76	)




	Asset Dispositions		–			–			75




	Environmental Remediation Provisions		(78	)		(191	)		(40	)




	Restructurings and Reorganizations		–			–			(46	)




	Litigation and Regulatory		–			(62	)		–

Total Special Items			(78	)		(253	)		(87	)

Segment Income		$	1,254		$	721		$	551

U.S. refining, marketing and transportation earnings in 2001, excluding special items, increased 37 percent to $1.332 billion and more than doubled 1999 earnings of $638 million. Amounts included the company’s share of equity income for the Equilon and Motiva joint ventures until the October 2001 merger, when these interests were placed in trust. Post-merger, the investments were accounted for on the cost basis, and earnings included dividend income, a component of other income, rather than the equity income as was recognized pre-merger.

Earnings increases in 2001 reflected significantly higher gasoline sales margins – especially early in the year – partially offset by weaker distillate sales margins and higher operating expense. Higher sales volumes across all major product lines also contributed to the improvement. Earnings in 2000 improved from 1999, particularly on the East and Gulf coasts. Earnings in 1999 suffered from lower sales margins and operational problems at the company’s California refineries.

Refined products sales volumes of 2.577 million barrels per day in 2001 decreased about 3 percent from 2000 and 2 percent from 1999. The 2001 sales volumes reflected pre-merger sales only for Equilon and Motiva. Sales in 2000 suffered from the effect of 1999 year-end stockpiling by customers in anticipation of possible Year 2000-related interruptions. The average U.S. refined products sales realization of $30.45 per barrel in 2001 was down 25 percent from the 2000 average of $40.75, but up 19 percent from depressed levels in 1999.

International Refining, Marketing and Transportation


Millions of dollars		2001			2000			1999

Earnings Excluding Special Items*		$	598		$	526		$	615

	Asset Write-Offs and Revaluations		(46	)		(112	)		–




	Asset Dispositions		–			–			(111	)




	Prior-Year Tax Adjustments		8			–			114




	Restructurings and Reorganizations		–			–			(72	)

Total Special Items			(38	)		(112	)		(69	)

Segment Income*		$	560		$	414		$	546






*Includes Foreign Currency Gains (Losses):		$	23		$	107		$	(27	)

International refining, marketing and transportation earnings include results of the company’s consolidated refining and marketing businesses, international marine operations, international supply and trading activities, and equity earnings of primarily Asia-Pacific affiliates. Excluding special items, 2001 earnings of $598 million were up 14 percent from 2000, but about 3 percent lower than in 1999.

Earnings in most of Asia, the Middle East and eastern Africa and South Africa operating areas improved significantly in 2001 because of improved marketing margins, particularly early in the year. Partially offsetting the marketing improvement were higher costs and somewhat lower refining margins. Earnings decreased in 2000, compared with 1999, on lower marketing margins and refined products sales volumes. The region suffered from a very competitive operating environment, including excess refinery capacity.

European operations suffered from low marketing and refining margins and lower sales volumes in 2001 compared with prior years, primarily due to weaker economic conditions. Latin American earnings were nearly level with 2000,with improved refining margins almost offsetting the declining sales volumes and marketing margins. In 2000, weaker margins in Latin America and West Africa resulted in lower earnings compared with 1999. These were partially offset by increased earnings in Europe, driven by higher margins in the United Kingdom and the Netherlands.

International refined products sales volumes were 2.495 million barrels per day in 2001, down about 1 percent from 2.521 million in 2000 and about 5 percent lower than 2.621 million in 1999. Weaker economic conditions, particularly in Europe, dampened demand in 2001. Lower trading volumes and the third quarter 1999 sale of the company’s equity interest in Koa Oil Company Limited in Japan were responsible for the decline in sales volumes in 2000.

FS-6

Chemicals


Millions of dollars		2001			2000			1999

(Loss) Earnings Excluding Special Items*		$	(32	)	$	130		$	174

	Asset Write-Offs and Revaluations		(96	)		(90	)		(43	)




	Restructurings and Reorganizations		–			–			(22	)

	Total Special Items		(96	)		(90	)		(65	)

	Segment (Loss) Income*	$	(128	)	$	40		$	109






	*Includes Foreign Currency (Losses) Gains:	$	(3	)	$	(2	)	$	3

Chemicals earnings include results from the company’s Oronite division, the company’s petrochemicals business prior to its contribution to CPChem in July 2000, and equity earnings in CPChem from that date. After excluding the effect of special items, the segment recorded a loss of $32 million in 2001, compared with earnings of $130 million in 2000 and $174 million in 1999. Results for all years reflected a protracted period of generally weak demand for commodity chemicals and industry over-capacity.

Special items in 2001 and 2000 include write-downs in the CPChem operations in Puerto Rico.

SELECTED OPERATING DATA


		2001		2000		1999

U.S. Exploration and Production




Net Crude Oil and Natural Gas Liquids Production (MBPD)			614		667		712




Net Natural Gas Production (MMCFPD)			2,706		2,910		3,145




Natural Gas Sales (MMCFPD)¹			7,830		7,302		6,534




Natural Gas Liquids Sales (MBPD)¹			340		373		415




Revenues from Net Production




	Crude Oil ($/Bbl)	$	21.70	$	26.69	$	15.50




	Natural Gas ($/MCF)	$	4.38	$	3.87	$	2.12









International Exploration and Production¹




Net Crude Oil and Natural Gas Liquids Production (MBPD)			1,345		1,330		1,337




Net Natural Gas Production (MMCFPD)			1,711		1,556		1,512




Natural Gas Sales (MMCFPD)			2,675		2,398		2,342




Natural Gas Liquids Sales (MBPD)			90		67		58




Revenues from Liftings




	Liquids ($/Bbl)	$	22.17	$	26.04	$	16.57




	Natural Gas ($/MCF)	$	2.36	$	2.09	$	1.66




Other Produced Volumes (MBPD)³			105		123		96









U.S. Refining, Marketing and Transportation^1,2




Gasoline Sales (MBPD)			1,246		1,320		1,266




Other Refined Products Sales (MBPD)			1,331		1,347		1,357




Refinery Input (MBPD)			1,286		1,337		1,484




Average Refined Products Sales Price ($/Bbl)		$	30.45	$	40.75	$	25.50









International Refining, Marketing and Transportation¹




Refined Products Sales (MBPD)			2,495		2,521		2,621




Refinery Input (MBPD)			1,136		1,150		1,235

		MBPD = Thousands of barrels per day; MMCFPD = Millions of cubic feet per day; Bbl = Barrel; MCF = Thousands of cubic feet.




		¹ Includes equity in affiliates.




		² Includes Equilon and Motiva pre-merger.




		³ Represents total field production under the Boscan operating service agreement in Venezuela, and in 2000 included a Colombian operating service agreement.

All Other


Millions of dollars		2001			2000			1999

Net Charges Excluding Special Items*		$	(883	)	$	(883	)	$	(899	)

	Asset Write-Offs and Revaluations		(152	)		–			(54	)




	Asset Dispositions		–			99			147




	Prior-Year Tax Adjustments		104			107			161




	Environmental Remediation		–			(73	)		–




	Restructurings and Reorganizations		–			–			(41	)




	Litigation and Regulatory		–			–			104




	Other		–			147			40

Total Special Items			(48	)		280			357

Merger Effects			(1,779	)		–			–

Segment Charges*		$	(2,710	)	$	(603	)	$	(542	)






*Includes Foreign Currency Losses:		$	(10	)	$	(20	)	$	–

All Other consists of coal mining operations, the company’s equity interest in Dynegy Inc. – a gatherer, processor, transporter and marketer of energy products – corporate administrative costs, worldwide cash management and debt financing activities, power and gasification ventures, technology investments and real estate and insurance activities.

Earnings, excluding special items, for coal operations were $19 million in 2001 compared with $1 million in 2000 and $34 million in 1999. The improved earnings in 2001 resulted from increased sales volumes, productivity improvements and the absence of a work stoppage that in 2000 lasted several months.

The company’s share of Dynegy earnings before special items in 2001 was $175 million, up from $119 million in 2000 and $44 million in 1999. Significantly higher prices for natural gas and natural gas liquids and an increase in earnings from power generation activities were the primary reasons for the improved results in 2001 from the previous periods.

Net charges for the balance of the All Other segment, excluding special items, were $1.077 billion in 2001, $1.003 billion in 2000 and $977 million in 1999. Increases in various corporate expenses essentially offset the benefits of lower interest expense and higher interest income in 2001 and 2000.

Merger effects in 2001 represented the sum of $1.136 billion for merger-related expenses and $643 million for losses on merger-related asset dispositions.

LIQUIDITY AND CAPITAL RESOURCES
Cash, cash equivalents and marketable securities were approximately $3.2 billion at the end of both 2001 and 2000. Cash provided by operating activities in 2001 was $11.5 billion, compared with $13.5 billion in 2000 and $7.8 billion in 1999. Cash provided by asset sales was $0.3 billion in 2001, $1.2 billion in 2000 and $1.6 billion in 1999. During 2001, the company’s overall debt levels increased to $17.4 billion at December 31, 2001, compared with $15.9 billion at December 31, 2000. Improved cash flows in 2000 permitted the company to reduce overall debt levels by $3.2 billion and repurchase $1.5 billion of the company’s common shares, net of sales. In addition, the company received a cash distribution of $835 million in 2000 from CPChem after the joint venture obtained debt financing. In 1999, a payment of $775 million was made to Occidental Petroleum in settlement of the Cities Service lawsuit.

FS-7

In February 2002, the company completed the sale of its investments in Equilon and Motiva to Shell and Saudi Refining Inc. for proceeds of $2.2 billion.

Dividends ChevronTexaco paid common stock dividends of $2,733 million, $2,664 million and $2,589 million in 2001, 2000 and 1999, respectively. Dividends on Texaco preferred shares were $6 million, $15 million and $28 million in 2001, 2000 and 1999, respectively. In addition, dividends of $119 million, $110 million and $55 million were paid for the three years to stockholders who hold minority interests in ChevronTexaco subsidiary companies.

Debt, lease and minority interest obligations ChevronTexaco’s total debt and capital lease obligations were $17.4 billion at December 31, 2001, up from $15.9 billion at year-end 2000. In addition, at December 31, 2001, the company had minority interest obligations of $283 million, down from $746 million at December 31, 2000. In 2001, net repayments of $2.4 billion in long-term debt were more than offset by proceeds of $3.8 billion from new short-term debt. Changes in long-term debt during 2001 included a non-cash reduction of $100 million of ESOP debt. In addition to the repayments of long-term debt during 2001, $463 million of Monthly Income Preferred shares, which were accounted for as minority interest, and $300 million of Texaco Market Auction Preferred Shares were redeemed.

At year-end 2001, ChevronTexaco had $3.2 billion in committed credit facilities with various major banks, which permit the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and also can be used for general credit requirements. No borrowings were outstanding under these facilities during the year or at year-end 2001. In addition, ChevronTexaco has three existing “shelf” registrations on file with the Securities and Exchange Commission that together would permit registered offerings of up to $2.8 billion of debt securities. Additionally, at December 31, 2001, the company had lines of credit available for short-term financing totaling $500 million, of which $210 million had not been utilized.

The company’s debt due within 12 months, consisting primarily of commercial paper and the current portion of long-term debt, totaled $11.6 billion at December 31, 2001, up from $8.2 billion at December 31, 2000. Of this total short-term debt, $3.2 billion was reclassified to long-term at year-end 2001. Settlement of these obligations was not expected to require the use of working capital in 2002, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis. The company’s practice has been to continually refinance its commercial paper, maintaining levels it believes to be appropriate.

The company’s future debt level is dependent primarily on its results of operations, its capital-spending program and cash that may be generated from asset dispositions. The company believes it has substantial borrowing capacity to meet unanticipated cash requirements. In periods of sustained low crude oil and natural gas prices (below levels of approximately $20 per barrel for West Texas Intermediate benchmark crude oil and $2.50 per thousand cubic feet for Henry Hub benchmark natural gas) and narrow refined products margins, cash provided by operating activities and asset sales may not be sufficient to fund the company’s investing activities and may result in increased borrowings or a reduction in overall cash levels. ChevronTexaco’s senior debt is rated AA by Standard and Poor’s Corporation and Aa2 by Moody’s Investor Service, except for senior debt of Texaco Inc. which is rated Aa3. ChevronTexaco’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and Prime 1 by Moody’s, and the company’s Canadian commercial paper is rated R-1 (middle) by Dominion Bond Rating Service. All of these ratings denote high-quality, investment-grade securities.

Share repurchase programs In December 1997, Chevron’s Board of Directors approved the repurchase of up to $2 billion of the company’s outstanding common stock for use in its employee stock option programs. Total repurchases from the program’s inception through the end of 2000 were 23.3 million shares at a cost of $1.9 billion. The program was formally terminated in September 2001.

In March 1998, Texaco’s Board of Directors approved the repurchase of up to $1 billion of Texaco’s outstanding common stock. This program was suspended in October 2000, prior to the announcement of the planned merger with Chevron. At that time, 11.4 million shares had been acquired at a cost of $643 million.

On- and off-balance-sheet arrangements The following tables summarize the company’s material on- and off-balance-sheet obligations at year-end 2001.

Contractual Obligations


Millions of dollars		Payments Due by Period

						2003–				After
		Total		2002		2005		2006		2006

On balance sheet:




Long-term debt¹		$	6,599	$	1,095	$	1,963	$	195	$	3,346




Short-term debt²			3,200		–		–		–		3,200




	Noncancelable capital lease obligations		954		80		214		47		613




Redemption of subsidiary’s preferred shares			199		–		199		–		–




Off balance sheet:




	Noncancelable operating lease obligations		2,541		692		881		237		731




	Unconditional purchase obligations		5,598		1,157		3,231		861		349




	Through-put and take-or-pay agreements		2,060		213		652		233		962

		¹ Includes guarantee of $535 of ESOP debt, $100 due in 2002, $85 during 2003 – 2005 and $350 due after 2006.




		² Continually refinanced on a long-term basis.

Commercial Commitments (Off Balance Sheet)


Millions of dollars	Commitment Expiration by Period

					2003 –				After
	Total		2002		2005		2006		2006

Guarantees of non-consolidated affiliates or joint venture obligations*	$	686	$	211	$	33	$	–	$	442




Guarantees of obligations of unrelated parties		742		141		225		34		342

Excludes $432 related to Equilon and Motiva. See Note 22.

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

In other off-balance-sheet arrangements, the company securitizes certain accounts receivable in its downstream business through the use of qualifying special purpose entities (SPEs). At December 31, 2001, approximately $850 million, representing about 10 percent of ChevronTexaco’s total current accounts receivable balance, were securitized. ChevronTexaco’s total estimated financial exposure under these arrangements at December 31, 2001, was approximately $50 million. These arrangements have the effect of accelerating ChevronTexaco’s collection of the securitized amounts. In the event of the SPEs experiencing major defaults in the collection of receivables, ChevronTexaco would have no loss exposure connected with third-party investments in these securitization arrangements.

The above information should also be read in conjunction with Note 22 to the Consolidated Financial Statements – Other Contingencies and Commitments on page FS-40.

FINANCIAL RATIOS
The year-end current ratio is the ratio of current assets to current liabilities. Generally, two items adversely affected ChevronTexaco’s current ratio, but in the company’s opinion do not affect its liquidity. First, current assets in all years included inventories valued on a LIFO basis, which at year-end 2001 were lower than replacement costs, based on average acquisition costs during the year, by nearly $1.6 billion. Also, because the company carries a larger percentage of short-term debt, it benefits from lower interest cost by continually refinancing its commercial paper.

The interest coverage ratio is defined as income before income tax expense, plus interest and debt expense and amortization of capitalized interest, divided by before-tax interest costs. ChevronTexaco’s interest coverage ratio was lower in 2001, primarily due to lower before-tax income partially offset by lower interest expense as a result of replacing long-term debt with lower interest rate commercial paper obligations. The company’s debt ratio (total debt divided by total debt plus equity) increased to 33.9 percent in 2001, due to an increase in total debt for the year.

Financial Ratios


	2001			2000			1999

Current Ratio		0.9			1.1			1.0




Interest Coverage Ratio		9.6			12.5			6.0




Total Debt/Total Debt Plus Equity		33.9	%		32.3	%		39.2	%

FINANCIAL AND DERIVATIVE INSTRUMENTS
Commodity Derivative Instruments ChevronTexaco is exposed to market risks related to the volatility of crude oil, refined products, natural gas and refinery feedstock prices. The company uses derivative commodity instruments to manage its exposure to price volatility on a small portion of its activity, including: firm commitments and anticipated transactions for the purchase or sale of crude oil, feedstock purchases for company refineries, crude oil and refined products inventories, and fixed-price contracts to sell natural gas and natural gas liquids.

ChevronTexaco also uses derivative commodity instruments for trading purposes, and the results of this activity are not material to the company’s financial position, net income or cash flows.

The company’s positions are monitored and managed on a daily basis by a risk control group to ensure compliance with the company’s stated risk management policy that has been approved by the company’s Board of Directors.

The derivative instruments used in the company’s risk management and trading activities consist mainly of futures contracts traded on the New York Mercantile Exchange and the International Petroleum Exchange, crude oil and natural gas swap contracts, options and other derivative products entered into principally with major financial institutions and other oil and gas companies. Virtually all derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income. Fair values are derived principally from market quotes and other independent third-party quotes.

The aggregate effect of a hypothetical 15 percent change in prices for natural gas, crude oil and petroleum products would not be material to the company’s financial position, net income or cash flows. The hypothetical loss on the related commodity contracts was estimated by calculating the cash value of the contracts as the difference between the hypothetical and contract delivery prices, multiplied by the contract amounts.

Foreign Currency The company enters into forward exchange contracts, generally with terms of 180 days or less, to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments forecasted to occur within 180 days. The forward exchange contracts are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.

The aggregate effect of a hypothetical adverse change of 10 percent to year-end exchange rates (a weakening of the U.S. dollar) would not be material to the company’s financial position, net income or cash flows.

Interest Rates The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements are based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts. Interest rate swaps hedging a portion of the company’s fixed-rate debt are accounted for as fair value hedges, whereas interest rate swaps relating to a portion of the company’s floating-rate debt are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. During 2001, no new swaps were initiated in connection with debt

FS-9

issues in the year. At year-end 2001, the weighted average maturity of interest rate swaps was approximately five years.

A hypothetical 10 percent increase in interest rates upon the interest rate swaps would cause the fair value of the “receive fixed” swaps to decline and the “receive floating” swaps to increase. The aggregate effect of these changes would not be material to the company’s financial position, net income or cash flows.

The company’s $1.5 billion investment in redeemable, convertible preferred stock of Dynegy is carried at fair value.

TRANSACTIONS WITH RELATED PARTIES
ChevronTexaco enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements. In the United States, there are long-term agreements in place with Dynegy for the purchase of substantially all natural gas and natural gas liquids produced by legacy Chevron in the United States, excluding Alaska, and the supply of natural gas and natural gas liquids feedstocks to the company’s U.S. refineries and chemicals plants. In early 2002, the company was negotiating to expand these agreements to include substantially all legacy Texaco U.S. production of natural gas and natural gas liquids. Internationally, there are long-term purchase agreements in place with the company’s refining affiliate in Thailand. Management believes the foregoing agreements and others have been negotiated on terms consistent with those that would have been negotiated with an unrelated third party.

CAPITAL AND EXPLORATORY EXPENDITURES
Worldwide capital and exploratory expenditures for 2001 totaled $12.0 billion,including the company’s equity share of affiliates’ expenditures. Capital and exploratory expenditures were $9.5 billion in 2000 and $10.1 billion in 1999. Expenditures for exploration and production activities represented 59 percent of total outlays in 2001, compared with 65 percent in 2000 and 72 percent in 1999. International exploration and production spending was 66 percent of worldwide exploration and production expenditures in 2001, compared with 62 percent in 2000 and 75 percent in 1999, reflecting the company’s continuing focus on international exploration and production activities. Expenditures in 2001 included additional investments in Tengizchevroil and the purchase of $1.5 billion of redeemable, convertible preferred shares of Dynegy stock. Expenditures in the All Other segment in 2000 included an additional investment of approximately $300 million in Dynegy Inc. Included in 1999 were expenditures of about $1.7 billion – mainly cash and assumption of debt – for the acquisition of Rutherford-Moran Oil Corporation and Petrolera Argentina San Jorge S.A., exploration and production businesses in Thailand and Argentina, respectively.

The company estimates 2002 capital and exploratory expenditures at $9.4 billion, including ChevronTexaco’s share of spending by affiliates. Excluding the 2001 amounts for the increased investment in Tengizchevroil and the Dynegy redeemable, convertible preferred stock, spending between years is expected to be about 9 percent lower in 2002. About $6.1 billion,or 65 percent of the total, is targeted for exploration and production activities, with $1.8 billion of that in the United States. Worldwide downstream spending is estimated at $1.7 billion,and investments in chemicals are budgeted at $400 million. Budgeted expenditures for power and related businesses are $800 million. The remaining $400 million is primarily targeted for emerging technologies and information technology infrastructure.

PRE-MERGER EMPLOYEE TERMINATION BENEFITS
AND OTHER RESTRUCTURING COSTS
Chevron recorded before-tax charges of $235 million in 1999 for employee termination benefits and other restructuring costs as part of a 3,500-employee reduction program in all its operating segments across several business functions. Employees affected were primarily U.S.-based, and all employee terminations were completed by December 2000. Termination benefits for approximately 3,100 of the 3,500 employees were paid from the assets of Chevron’s U.S. and Canadian pension plans.

In the fourth quarter 1998, Texaco recorded $115 million before tax for a corporatewide reorganization affecting 1,400 employees. During the second quarter 1999, the program was expanded by about 1,200 employees and an additional $48 million before-tax was accrued. By the end of the third quarter 2000, the employee reductions were met and all termination payments were made.

During the first quarter of 2000, Texaco recorded $17 million before tax for the termination of an additional 200 employees. Terminations and payments were completed by the end of the first quarter 2001.

Caltex recorded charges of $37 million in 1999 for restructuring activities that included severance and other termination benefits of $23 million for 200 employees. By December 2000, all work force reductions and separation payments were completed.

ENVIRONMENTAL MATTERS
Virtually all aspects of the businesses in which the company engages are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to increase in both number and complexity over time and govern not only the manner in which the


Capital and Exploratory Expenditures					2001						2000						1999

			Inter-						Inter-						Inter-
Millions of dollars	U.S.		national		Total		U.S.		national		Total		U.S.		national		Total

Exploration and Production	$	2,420	$	4,709	$	7,129	$	2,354	$	3,897	$	6,251	$	1,811	$	5,479	$	7,290




Refining, Marketing and Transportation		873		1,271		2,144		919		1,121		2,040		946		1,003		1,949




Chemicals		145		34		179		135		51		186		326		136		462




All Other		2,570		6		2,576		891		152		1,043		311		125		436

Total	$	6,008	$	6,020	$	12,028	$	4,299	$	5,221	$	9,520	$	3,394	$	6,743	$	10,137

Total, Excluding Equity in Affiliates	$	4,934	$	5,382	$	10,316	$	3,594	$	4,697	$	8,291	$	2,871	$	6,161	$	9,032

FS-10

company conducts its operations, but also the products it sells. Most of the costs of complying with laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business.

Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In addition to the costs for environmental protection associated with its ongoing operations and products, the company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party owned waste-disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-ChevronTexaco sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative and/or remedial work to meet current standards.

Using definitions and guidelines established by the American Petroleum Institute, ChevronTexaco estimated its world-wide environmental spending in 2001 at $1.246 billion for its consolidated companies. Included in these expenditures were $323 million of environmental capital expenditures and $923 million of costs associated with the control and abatement of hazardous substances and pollutants from ongoing operations. For 2002, total worldwide environmental capital expenditures are estimated at $495 million. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.

The following table analyzes the annual changes to the company’s before-tax environmental remediation reserves, including those for Superfund sites. For 2001, the company recorded additional provisions for estimated remediation costs at refined products marketing sites and various producing properties in the United States.


Millions of dollars	2001			2000			1999

Balance at January 1	$	1,234		$	1,079		$	1,132




Expense Provisions		216			429			275




Expenditures		(290	)		(274	)		(328	)

Balance at December 31	$	1,160		$	1,234		$	1,079

Under provisions of the Superfund law, the Environmental Protection Agency (EPA) has designated ChevronTexaco a potentially responsible party, or has otherwise involved the company, in the remediation of 413 hazardous waste sites. The company made provisions or payments in 2001 and prior years for approximately 287 of these sites. No single site is expected to result in a material liability for the company. For the remaining sites, investigations are not yet at a stage where the company is able to quantify a probable liability or determine a range of reasonably possible exposures. The Superfund law provides for joint and several liability for all responsible parties. Any future actions by the EPA and other regulatory agencies to require ChevronTexaco to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s consolidated financial position or liquidity. Remediation reserves at year-end 2001, 2000 and 1999 for Superfund sites were $62 million, $73 million and $79 million, respectively.

It is likely that the company will continue to incur additional liabilities, beyond those recorded, for environmental remediation relating to past operations. These future costs are 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 amount of future costs may be material to the company’s results of operations in the period in which they are recognized, the company does not expect these costs will have a material adverse 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 petroleum or chemicals companies.

The company maintains additional reserves for dismantlement, abandonment and restoration of its worldwide oil and gas and coal properties at the end of their productive lives. Many of these costs are related to environmental issues. Expense provisions are recognized on a unit-of-production basis. The reserves balance at year-end 2001 was $2.2 billion and is included in “Accumulated depreciation, depletion and amortization” in the company’s Consolidated Balance Sheet.

For the company’s other ongoing operating assets, such as refineries and chemicals facilities, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives, unless a decision to sell or otherwise abandon the facility has been made.

LITIGATION AND OTHER UNCERTAINTIES
Chevron, Texaco and four other oil companies (refiners) filed suit in 1995 contesting the validity of a patent granted to Unocal Corporation (Unocal) for reformulated gasoline, which ChevronTexaco sells in California in certain months of the year. In March 2000, the U.S. Court of Appeals for the Federal Circuit upheld a September 1998 District Court decision that Unocal’s patent was valid and enforceable and assessed damages of 5.75 cents per gallon for gasoline produced in infringement of the patent. In May 2000, the Federal Circuit Court denied a petition for rehearing with the U.S. Court of Appeals for the Federal Circuit filed by the refiners in this case. The refiners petitioned the U.S. Supreme Court, and in February 2001, the Supreme Court denied the petition to review the lower court’s ruling, and the case was remanded to the District Court for an accounting of all infringing gasoline produced from August 1, 1996, to September 30, 2000. The District Court granted Unocal’s motion for summary judgment requesting an accounting and denied the refiners’ motion to stay the proceedings and vacate the accounting order. However, the judge presiding over this case recused himself before entering a final judgment and a new judge was assigned. Additionally, in May 2001, the U.S. Patent Office (USPO) granted the refiners’petition to reexamine the validity of Unocal’s patent and in February 2002, the USPO ruled the patent invalid. Unocal has two months to respond to the USPO ruling. The Federal Trade Commission also announced that it was investigating whether Unocal’s failure to disclose to the California Air Resources Board that it had filed a patent application was unfair competition, which may make Unocal’s patent unenforceable.

FS-11

If Unocal’s patent ultimately is upheld and is enforceable, the company’s financial exposure includes royalties, plus interest, for production of gasoline that is proven to have infringed the patent. Chevron and Texaco, as well as Texaco’s former affiliates Equilon and Motiva, have been accruing in the normal course of business any future estimated liability for potential infringement of the patent covered by the trial court’s ruling. In 2000, Chevron and Texaco made payments to Unocal totaling approximately $28 million for the original court ruling, including interest and fees.

Unocal obtained additional patents for alternate formulations that could affect a larger share of U.S. gasoline production. ChevronTexaco believes these additional patents are invalid and unenforceable. However, if such patents are ultimately upheld, the competitive and financial effects on the company’s refining and marketing operations, while presently indeterminable, could be material.

Another issue involving the company is the petroleum industry’s use of methyl tertiary-butyl ether (MTBE) as a gasoline additive and its potential environmental impact through seepage into groundwater. Along with other oil companies, the company is a party to lawsuits and claims related to the use of the chemical MTBE in certain oxygenated gasolines. These actions may require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. Total costs to the company related to these lawsuits and claims are not currently determinable. ChevronTexaco continues the use of MTBE in gasoline it sells in certain areas. The state of California had directed that MTBE be phased out of the manufacturing process by the end of 2002. In March 2002, the governor of California postponed the phase out of MTBE in California until the end of 2003.

See “Environmental Matters” on page FS-10 for comments related to uncertainties connected with environmental cost estimates and financial exposures.

At year-end 2001, the projected benefit obligations exceeded the value of the assets in the company’s combined U.S. pension plans by $780 million. If investment returns are insufficient to offset increases in the plan’s obligations, pension expense may increase and additional funding may be required.

The U.S. federal income tax liabilities have been settled through 1993 for Chevron and Caltex and through 1991 for Texaco. California franchise tax liabilities have been settled through 1991 for Chevron and through 1987 for Texaco. Settlement of open tax years, as well as tax issues in other countries where the company conducts its businesses, is not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provision has been made for income and franchise taxes for all years under examination or subject to future examination.

The company’s operations, particularly exploration and production, can be affected by other changing economic, regulatory and political environments in the various countries in which it operates, including the United States. In certain locations, host governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries. Internal unrest or strained relations between a host government and the company or other governments may affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries.

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

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

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 may 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.

FS-12

CRITICAL ACCOUNTING POLICIES
In December 2001, the Securities and Exchange Commission (SEC) issued a statement addressing selection and disclosure by public companies of “critical accounting policies and practices.” In the statement, the SEC encouraged inclusion in Management’s Discussion and Analysis (MD&A) commentary as to “the likelihood of materially different reported results if different assumptions or conditions were to prevail” in the application of these critical accounting policies.

The accompanying ChevronTexaco consolidated financial statements and supplementary information were prepared in accordance with accounting principles generally accepted in the United States (GAAP). Significant accounting policies are discussed in Note 1 to the Consolidated Financial Statements. Inherent in the application of many of these accounting policies is the need for management to make estimates and judgments in the determination of certain revenues, expenses, assets and liabilities. As such, materially different financial results can occur as circumstances change and additional information becomes known. Differences have occurred in the past with respect to a few critical accounting policies, as follows:

Successful Efforts Method of Oil and Gas Accounting Among other things, this accounting principle requires that capitalized costs for producing properties be amortized on the basis of crude oil and natural gas reserve quantities. The reserve estimates are determined in accordance with earth science and petroleum engineering principles and practices – and can vary as a result of changes in such factors as forecasted oil and gas prices, reservoir performance and oil field technology.

Downward revision in reserve estimates (on a field basis in North America; by concession or country in other producing areas) can result in either: (a) higher depreciation and depletion expense per barrel in future periods, or (b) an immediate write-down of the asset’s book value in accordance with accounting rules for the impairment of properties. The latter condition would result if the downward revisions were so significant that the estimated future cash flows from the remaining reserves in the field were insufficient to recover the unamortized capitalized costs. Conversely, if the oil and gas reserve quantities were revised upward, future per-barrel depreciation and depletion expense would be lower.

The application of successful efforts accounting can also cause material fluctuations between periods in exploration expense if drilling results are different than expected or if the company changes its exploration and development plans. The determination that exploratory drilling was unsuccessful in finding economically producible reserves requires the immediate expensing of previously capitalized drilling costs.

Impairment of Long-Lived Assets In addition to oil and gas assets that could become impaired under the application of successful efforts accounting, other assets could become impaired and require write-down if circumstances warrant. Conditions that could cause an asset to become impaired include lower-than-forecasted commodity sales prices, changes in the company’s business plans or a significant adverse change in the local or national business climate. The amount of an impairment charge would be based on estimates of an asset’s fair value compared with its book value.

Environmental Remediation and Litigation Reserve Estimation Management also makes judgments and estimates in recording liabilities for environmental cleanup and litigation. Liabilities for environmental remediation are subject to change because of matters such as changes in laws, regulations and their interpretation; the determination of additional information on the extent and nature of site contamination; and improvements in technology. Likewise, actual litigation costs can vary from estimates based on the facts and circumstance and application of laws in individual cases.

Income Tax Accounting The computation of the company’s income tax expense requires the interpretation of complex tax laws and regulations in many taxing jurisdictions around the world; the determination of expected outcomes from pending litigation; and the assessment of audit findings that are performed by numerous taxing authorities. Actual income tax expense can differ significantly from management’s estimates.

The above assessment of critical accounting policies is not meant to be an all-inclusive discussion of the uncertainties to financial results that can occur from the application of the full range of the company’s accounting policies. Materially different financial results could occur in the application of other accounting policies as well. Likewise, materially different results can occur upon the adoption of new accounting standards promulgated by the various rule-making bodies.

Other contingencies are discussed in Note 22 to the Consolidated Financial Statements. The status of pending litigation and other information is included in Note 12 to the Consolidated Financial Statements. Information on contingencies and litigation is also addressed on page FS-11.

NEW ACCOUNTING STANDARDS
The company adopted the Financial Accounting Standards Board (FASB) Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS 133), as amended by FAS 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities – an amendment of FASB Statement No. 133,” effective January 1, 2001. The adoption of FAS 133 and FAS 138 did not have a significant impact on the company’s results of operations, financial position or liquidity.

Recent interpretations of FAS 133 and FAS 138 by the FASB Derivatives Implementation Group prescribe mark-to-market accounting for certain natural gas sales contracts. Some of these interpretations became effective January 1, 2002. Adoption at that time did not result in a material effect to earnings. The effect of subsequent changes in the contracts’ fair values is uncertain.

In September 2000, the FASB issued Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities – A Replacement of FASB Statement No. 125” (FAS 140). FAS 140 is effective for transfers occurring after March 31, 2001, and for disclosures relating to securitization transactions and collateral for fiscal years ending after December 15, 2000. Adoption of FAS 140 had no significant effect on ChevronTexaco’s accounting or disclosures for the types of transactions in the scope of the new standard.

In June 2001, the FASB issued Statement No. 141, “Business Combinations” (FAS 141), Statement No. 142, “Goodwill and Other Intangible Assets” (FAS 142) and Statement No. 143,

FS-13

“Accounting for Asset Retirement Obligations” (FAS 143). FAS 141 is effective for all business combinations initiated after June 30, 2001, and for all business combinations accounted for using the purchase method for which the date of acquisition is July 1, 2001, or later. FAS 142 is effective for fiscal years beginning after December 15, 2001, except for goodwill and intangible assets acquired after June 30, 2001, which were immediately subject to the amortization and nonamortization provisions of the Statement. FAS 143 is effective for fiscal years beginning after June 15, 2002. Adoption of FAS 141 will have no effect on the company’s pooling-of-interests method of accounting for the Texaco merger transaction, but will affect future transactions. Similarly, adoption of FAS 142 may affect future transactions, but is not expected to have an effect on the company’s prior business combinations. FAS 143 differs in several significant respects from current accounting for asset retirement obligations under FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Adoption of FAS 143 will affect future accounting and reporting of the assets, liabilities and expenses related to these obligations. The magnitude of the effect has not yet been determined.

In August 2001, the FASB issued Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (FAS 144). FAS 144 is effective for fiscal years beginning after December 15, 2001, with initial application effective as of the beginning of the fiscal year adopted. Adoption of FAS 144 will not affect assets classified as held for disposal as a result of disposal activities that were initiated prior to its initial application, but may affect future disposals.

FS-14

REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS AND THE BOARD OF DIRECTORS OF CHEVRONTEXACO CORPORATION

In our opinion, based on our audits and the report of other auditors, the consolidated financial statements listed in the index appearing under Item 14 (a)(1) on page 25 present fairly, in all material respects, the financial position of ChevronTexaco Corporation and its subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. In addition, based on our audits and the report of other auditors, the financial statement schedule listed in the index appearing under Item 14(a)(2) on page 25 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. The consolidated financial statements give retroactive effect to the merger of Texaco Inc. on October 9, 2001, in a transaction accounted for as a pooling of interests, as described in Note 2 to the consolidated financial statements. We did not audit the financial statements or financial statement schedule of Texaco Inc., which statements reflect total assets of $30,867 million as of December 31, 2000, and total revenues of $51,130 million and $35,691 million for each of the two years in the period ended December 31, 2000. Those statements and schedule were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for Texaco Inc., is based solely on the report of the other auditors. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
San Francisco, California
March 8, 2002

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Shareholders, Texaco Inc.:

We have audited the consolidated balance sheet of Texaco Inc. (a Delaware corporation) and subsidiary companies as of December 31, 2000 and 1999, and the related consolidated statements of income, stockholders’ equity, comprehensive income and cash flows for each of the two years in the period ended December 31, 2000. These financial statements (not presented separately herein) are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above (not presented separately herein) present fairly, in all material respects, the financial position of Texaco Inc. and subsidiary companies as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States.

Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in Item 14 on Texaco Inc.’s 2000 Form 10-K (not presented separately herein) is the responsibility of the Company’s management and is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

ARTHUR ANDERSEN LLP

February 22, 2001
New York, New York

FS-15

Consolidated Statement of Income¹


				Year ended December 31

Millions of dollars, except per-share amounts				2001			2000		1999

REVENUES AND OTHER INCOME




	Sales and other operating revenues²			$	104,409		$	117,095	$	84,004




	Income from equity affiliates				1,144			1,077		896




	Other income				692			958		813

TOTAL REVENUES AND OTHER INCOME					106,245			119,130		85,713

COSTS AND OTHER DEDUCTIONS




	Purchased crude oil and products				60,549			69,814		46,256




	Operating expenses				7,650			8,323		7,773




	Selling, general and administrative expenses				3,984			3,626		3,222




	Exploration expenses				1,039			949		1,072




	Depreciation, depletion and amortization				7,059			5,321		4,934




	Merger-related expenses				1,563			—		—




	Interest and debt expense				833			1,110		1,132




	Taxes other than on income²				15,156			15,827		15,441




	Minority interests				121			111		71

TOTAL COSTS AND OTHER DEDUCTIONS					97,954			105,081		79,901

INCOME BEFORE INCOME TAX EXPENSE					8,291			14,049		5,812




INCOME TAX EXPENSE					4,360			6,322		2,565

NET INCOME BEFORE EXTRAORDINARY ITEM				$	3,931		$	7,727	$	3,247




	Extraordinary loss, net of income tax				(643	)		—		—

NET INCOME				$	3,288		$	7,727	$	3,247

PER-SHARE AMOUNTS




NET INCOME BEFORE EXTRAORDINARY ITEM – BASIC				$	3.71		$	7.23	$	3.01




			– DILUTED	$	3.70		$	7.21	$	3.00




NET INCOME – BASIC				$	3.10		$	7.23	$	3.01




		– DILUTED		$	3.09		$	7.21	$	3.00

¹ 2000 and 1999 include certain reclassifications to conform to 2001 presentation




² Includes consumer excise taxes:				$	6,546		$	6,601	$	6,029

See accompanying Notes to Consolidated Financial Statements.

REPORT OF MANAGEMENT
TO THE STOCKHOLDERS OF CHEVRONTEXACO CORPORATION

Management of ChevronTexaco is responsible for preparing the accompanying financial statements and for ensuring their integrity and objectivity. The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgments.

The company’s statements have been audited by PricewaterhouseCoopers LLP, independent accountants, selected by the Audit Committee and approved by the stockholders. Management has made available to PricewaterhouseCoopers LLP all the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.

Management of the company has established and maintains a system of internal accounting controls that is designed to provide reasonable assurance that assets are safeguarded, transactions are properly recorded and executed in accordance with management’s authorization, and the books and records accurately reflect the disposition of assets. The system of internal controls includes appropriate division of responsibility. The company maintains an internal audit department that conducts an extensive program of internal audits and independently assesses the effectiveness of the internal controls.

The Audit Committee is composed of directors who are not officers or employees of the company. It meets regularly with members of management, the internal auditors and the independent accountants to discuss the adequacy of the company’s internal controls, its financial statements, and the nature, extent and results of the audit effort. Both the internal auditors and the independent accountants have free and direct access to the Audit Committee without the presence of management.


/s/ David J. O’Reilly DAVID J. O’REILLY Chairman of the Board and Chief Executive Officer		/s/ John S. Watson JOHN S. WATSON Vice President and Chief Financial Officer		/s/ Stephen J. Crowe STEPHEN J. CROWE Vice President and Comptroller

March 8, 2002

FS-16

Consolidated Statement of Comprehensive Income


			Year ended December 31

Millions of dollars			2001			2000			1999

NET INCOME			$	3,288		$	7,727		$	3,247

Unrealized holding gain on securities




	Net gain arising during period




		Before income taxes		3			87			72




		Income taxes		—			(30	)		(33	)




	Reclassification to net income of net realized gain




		Before income taxes		—			(154	)		(48	)




		Income taxes		—			54			11

	Total			3			(43	)		2

Net derivatives gain on hedge transactions				3			—			—

Minimum pension liability adjustment




		Before income taxes		14			(28	)		(15	)




		Income taxes		(5	)		9			5

	Total			9			(19	)		(10	)

Currency translation adjustment




	Unrealized net change arising during period			(11	)		(14	)		(21	)




	Reclassification adjustment to net income for sale of investment in affiliate			—			—			(14	)

	Total			(11	)		(14	)		(35	)

OTHER COMPREHENSIVE GAIN (LOSS), NET OF TAX				4			(76	)		(43	)

COMPREHENSIVE INCOME			$	3,292		$	7,651		$	3,204

See accompanying notes to Consolidated Financial Statements.

FS-17

Consolidated Balance Sheet


			At December 31

Millions of dollars, except per-share amounts			2001			2000

ASSETS




	Cash and cash equivalents		$	2,117		$	2,328




	Marketable securities			1,033			913




	Accounts and notes receivable (less allowance: 2001 - $152; 2000 - $116)			8,279			10,763




	Inventories:




		Crude oil and petroleum products		2,207			1,969




		Chemicals		209			200




		Materials, supplies and other		532			485

				2,948			2,654




	Prepaid expenses and other current assets			1,769			1,255




	Assets held for sale – merger related			2,181			—

	TOTAL CURRENT ASSETS			18,327			17,913




	Long-term receivables, net			1,225			1,218




	Investments and advances			12,252			11,764




	Properties, plant and equipment, at cost			99,943			95,568




	Less: accumulated depreciation, depletion and amortization			56,710			51,249

				43,233			44,319




	Deferred charges and other assets			2,535			2,407

	TOTAL ASSETS		$	77,572		$	77,621

LIABILITIES AND STOCKHOLDERS’ EQUITY




	Short-term debt		$	8,429		$	3,094




	Accounts payable			6,427			7,563




	Accrued liabilities			3,399			3,014




	Federal and other taxes on income			1,398			1,864




	Other taxes payable			1,001			1,126

	TOTAL CURRENT LIABILITIES			20,654			16,661




	Long-term debt			8,704			12,494




	Capital lease obligations			285			327




	Deferred credits and other noncurrent obligations			4,394			4,303




	Noncurrent deferred income taxes			6,132			6,687




	Reserves for employee benefit plans			3,162			3,034




	Minority interests			283			746

	TOTAL LIABILITIES			43,614			44,252

	Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued)			—			—




	Market Auction Preferred Shares (authorized 30,000,000 shares, $1.00 par value, 1,200 issued, liquidation preference of $250,000 per share)			—			300




	Common stock (authorized 4,000,000,000 shares, $0.75 par value; 1,137,021,057 shares issued at December 31, 2001; 1,149,520,976 shares issued at December 31, 2000)			853			862




	Capital in excess of par value			4,811			5,505




	Retained earnings			32,767			32,206




	Accumulated other comprehensive loss			(306	)		(310	)




	Deferred compensation and benefit plan trust			(752	)		(921	)




	Treasury stock, at cost (2001 - 69,800,315 shares; 2000 - 84,835,000 shares)			(3,415	)		(4,273	)

	TOTAL STOCKHOLDERS’ EQUITY			33,958			33,369

	TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	77,572		$	77,621

See accompanying notes to Consolidated Financial Statements.

FS-18

Consolidated Statement of Cash Flows


			Year ended December 31

Millions of dollars			2001			2000			1999

OPERATING ACTIVITIES




	Net income		$	3,288		$	7,727		$	3,247




	Adjustments




	Depreciation, depletion and amortization			7,059			5,321			4,934




		Dry hole expense		646			462			583




		Distributions less than income from equity affiliates		(489	)		(26	)		(288	)




		Net before-tax gains on asset retirements and sales		(116	)		(371	)		(542	)




		Net foreign currency (gains) losses		(122	)		(130	)		58




		Deferred income tax (credits) charges		(768	)		521			23




		Extraordinary before-tax loss on merger-related asset dispositions		787			—			—




		Net decrease in operating working capital		643			91			266




		Minority interest in net income		121			111			68




		Decrease in Cities Service provision		—			—			(149	)




		Cash settlement of Cities Service litigation		—			—			(775	)




		Other, net		408			(239	)		346

NET CASH PROVIDED BY OPERATING ACTIVITIES				11,457			13,467			7,771

INVESTING ACTIVITIES




	Capital expenditures			(9,713	)		(7,629	)		(7,895	)




	Proceeds from asset sales			298			1,229			1,578




	Net (purchases) sales of marketable securities			(183	)		80			597




	Net sales (purchases) of other short-term investments			56			(84	)		—




	Collection of note/formation payments from U.S. affiliate			—			—			101




	Distribution from Chevron Phillips Chemical Company LLC			—			835			—




	Other, net			—			(73	)		9

NET CASH USED FOR INVESTING ACTIVITIES				(9,542	)		(5,642	)		(5,610	)

FINANCING ACTIVITIES




	Net borrowings (repayments) of short-term obligations			3,830			(3,254	)		542




	Proceeds from issuances of long-term debt			412			1,293			2,383




	Repayments of long-term debt and other financing obligations			(2,856	)		(1,241	)		(1,491	)




	Redemption of Market Auction Preferred Shares			(300	)		—			—




	Redemption of subsidiary preferred stock			(463	)		—			—




	Issuance of preferred stock by subsidiaries			12			—			—




	Dividends paid




		Common stock		(2,733	)		(2,664	)		(2,589	)




		Preferred stock		(6	)		(15	)		(28	)




	Dividends paid to minority interests			(119	)		(110	)		(55	)




	Net sales (purchases) of treasury shares			128			(1,498	)		108

NET CASH USED FOR FINANCING ACTIVITIES				(2,095	)		(7,489	)		(1,130	)

EFFECT OF FOREIGN CURRENCY EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS				(31	)		(5	)		(30	)

NET CHANGE IN CASH AND CASH EQUIVALENTS				(211	)		331			1,001




CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR				2,328			1,997			996

CASH AND CASH EQUIVALENTS AT YEAR – END			$	2,117		$	2,328		$	1,997

See accompanying Notes to Consolidated Financial Statements

FS-19

Consolidated Statement of Stockholders’ Equity


				2001						2000					1999

Shares in thousands; amounts in millions of dollars				Shares			Amount			Shares		Amount			Shares			Amount

PREFERRED STOCK					—		$	—			—	$	—			—		$	—




MARKET AUCTION PREFERRED SHARES




	Balance at January 1				1		$	300			—	$	—			—		$	—




	Redemptions				(1	)		(300	)		—		—			—			—

	BALANCE AT DECEMBER 31				—		$	—			1	$	300			1		$	300

SERIES B ESOP CONVERTIBLE PREFERRED STOCK




	Balance at January 1				—		$	—			—	$	—			649		$	389




	Redemptions				—			—			—		—			(587	)		(352	)




	Retirements				—			—			—		—			(62	)		(37	)

	BALANCE AT DECEMBER 31				—		$	—			—	$	—			—		$	—

SERIES F ESOP CONVERTIBLE PREFERRED STOCK




	Balance at January 1				—		$	—			—	$	—			53		$	39




	Redemptions				—			—			—		—			(53	)		(39	)




	Retirements				—			—			—		—			—			—

	BALANCE AT DECEMBER 31				—		$	—			—	$	—			—		$	—

COMMON STOCK




	Balance at January 1				1,149,521		$	862			1,149,521	$	1,724			1,149,544		$	1,724




	Retirement of Texaco treasury stock				(12,500	)		(9	)		—		—			—			—




	Change in par value				—			—			—		(862	)		—			—




	Monterey Resources acquisition adjustment				—			—			—		—			(23	)		—

	BALANCE AT DECEMBER 31				1,137,021		$	853			1,149,521	$	862			1,149,521		$	1,724

CAPITAL IN EXCESS OF PAR




	Balance at January 1						$	5,505				$	4,621					$	4,856




	Retirement of Texaco treasury stock							(739	)				—						—




	Change in common stock par value							—					862						—




	Redemption of Texaco Series B and Series F ESOP convertible preferred stock							—					—						(308	)




	Monterey Resources acquisition adjustment							—					—						(2	)




	Treasury stock transactions							45					22						75

	BALANCE AT DECEMBER 31						$	4,811				$	5,505					$	4,621

RETAINED EARNINGS




	Balance at January 1						$	32,206				$	27,148					$	26,503




	Net income							3,288					7,727						3,247




	Cash dividends




		Common stock						(2,733	)				(2,664	)					(2,589	)




		Preferred stock




			Texaco Series B ESOP convertible preferred stock					—					—						(17	)




			Texaco Series F ESOP convertible preferred stock					—					—						(2	)




			Market Auction Preferred Shares					(6	)				(17	)					(9	)




	Tax benefit from dividends paid on unallocated ESOP shares and other							12					12						15

	BALANCE AT DECEMBER 31						$	32,767				$	32,206					$	27,148

FS-20

Consolidated Statement of Stockholders’ Equity – Continued


							2001						2000						1999

Shares in thousands; amounts in millions of dollars				Shares			Amount			Shares			Amount			Shares			Amount

ACCUMULATED OTHER COMPREHENSIVE LOSS




	Currency translation adjustment




		Balance at January 1					$	(212	)				$	(198	)				$	(163	)




		Change during year						(11	)					(14	)					(35	)

		Balance at December 31					$	(223	)				$	(212	)				$	(198	)




	Minimum pension liability adjustment




		Balance at January 1					$	(100	)				$	(81	)				$	(71	)




		Change during year						9						(19	)					(10	)

		Balance at December 31					$	(91	)				$	(100	)				$	(81	)




	Unrealized net holding gain on securities




		Balance at January 1					$	2					$	45					$	43




		Change during year						3						(43	)					2

		Balance at December 31					$	5					$	2					$	45




	Net derivatives gain on hedge transactions




		Balance at January 1					$	—					$	—					$	—




		Change during year						3						—						—

		Balance at December 31					$	3					$	—					$	—




	BALANCE AT DECEMBER 31						$	(306	)				$	(310	)				$	(234	)

DEFERRED COMPENSATION AND BENEFIT PLAN TRUST




	DEFERRED COMPENSATION




		Balance at January 1					$	(681	)				$	(712	)				$	(785	)




		Net reduction of ESOP debt and other						106						35						45




		Restricted stock Awards						(35	)					(30	)					(18	)




			Amortization and other					12						26						46




			Vesting upon merger					86						—						—

		BALANCE AT DECEMBER 31						(512	)					(681	)					(712	)




	BENEFIT PLAN TRUST (COMMON STOCK)				7,084			(240	)		7,084			(240	)		7,084			(240	)

	BALANCE AT DECEMBER 31				7,084		$	(752	)		7,084		$	(921	)		7,084		$	(952	)

TREASURY STOCK AT COST




	Balance at January 1				84,835		$	(4,273	)		67,282		$	(2,816	)		84,853		$	(3,728	)




	Purchases				141			(9	)		19,517			(1,580	)		56			(5	)




	Retirement of Texaco treasury stock				(12,500	)		748			—			—			—			—




	Redemption of Texaco Series B and Series F ESOP convertible stock				—			—			—			—			(12,459	)		699




	Other — mainly employee benefit plans				(2,676	)		119			(1,964	)		123			(5,168	)		218

BALANCE AT DECEMBER 31					69,800		$	(3,415	)		84,835		$	(4,273	)		67,282		$	(2,816	)

TOTAL STOCKHOLDERS’ EQUITY AT DECEMBER 31							$	33,958					$	33,369					$	29,791

See accompanying notes to Consolidated Financial Statements.

FS-21

Notes to Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation – Merger of Chevron and Texaco On October 9, 2001, Texaco Inc. (Texaco) became a wholly owned subsidiary of Chevron Corporation (Chevron) pursuant to a merger transaction, and Chevron changed its name to ChevronTexaco Corporation. The combination was accounted for as a pooling of interests.

These Consolidated Financial Statements give retroactive effect to the merger, with all periods presented as if Chevron and Texaco had always been combined. Certain reclassifications have been made to conform the separate presentations of Chevron and Texaco. The reclassifications had no impact on the amount of net income or stockholders’ equity.

The Consolidated Financial Statements include the accounts of all majority-owned, controlled subsidiaries after the elimination of significant intercompany accounts and transactions. Included in the consolidation are the accounts of the Caltex Group of Companies (Caltex) – a joint venture, owned 50 percent each by Chevron and Texaco prior to the merger and accounted for under the equity method by both companies.

General ChevronTexaco manages its investments in, and provides administrative, financial and management support to, U.S. and foreign subsidiaries and affiliates that engage in fully integrated petroleum operations, chemicals operations and coal mining activities. In addition, ChevronTexaco holds investments in power generation and gasification businesses. Collectively, these companies operate in approximately 180 countries. Petroleum operations consist of exploring for, developing and producing crude oil and natural gas; refining crude oil into finished petroleum products; marketing crude oil, natural gas and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipelines, marine vessels, motor equipment and rail car. Chemicals operations include the manufacture and marketing of commodity petrochemicals, plastics for industrial uses and fuel and lube oil additives.

In preparing its Consolidated Financial Statements, the company follows accounting policies that are in accordance with accounting principles generally accepted in the United States. This requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. While the company uses its best estimates and judgments, actual results could differ from these estimates as future confirming events occur.

The nature of the company’s operations and the many countries in which it operates subject it to changing economic, regulatory and political conditions. The company does not believe it is vulnerable to the risk of near-term severe impact as a result of any concentration of its activities.

Subsidiary and Affiliated Companies The consolidated financial statements include the accounts of controlled subsidiary companies more than 50 percent owned. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent, or for which the company exercises significant influence but not control over policy decisions are accounted for by the equity method, in accordance with Accounting Principles Board (APB) Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” Under this accounting, remaining unamortized cost is increased or decreased by the company’s share of earnings or losses after dividends. Gains and losses that arise from the issuance of stock by an affiliate that results in changes in the company’s proportionate share of the dollar amount of the affiliate’s equity are recognized currently in income. Deferred income taxes are provided for these gains and losses.

Derivatives The majority of the company’s activity in commodity derivative instruments is intended to manage the price risk posed by physical transactions. For some of this derivative activity, generally limited to large, discrete or infrequently occurring transactions, the company may elect to apply fair value or cash flow hedge accounting. For other similar derivative instruments, generally because of the short-term nature of the contracts and their limited use, the company has elected not to apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s trading activity, gains and losses from the derivative instruments are reported in current income. For derivative instruments relating to foreign currency exposures, gains and losses are reported in current income. Interest rate swaps – hedging a portion of the company’s fixed rate debt – are accounted for as fair value hedges, whereas interest rate swaps relating to a portion of the company’s floating-rate debt are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.

Short-Term Investments All short-term investments are classified as available for sale and are in highly liquid debt or equity securities. Those investments that are part of the company’s cash management portfolio with original maturities of three months or less are reported as “Cash equivalents.” The balance of the short-term investments is reported as “Marketable securities.” Short-term investments are marked-to-market with any unrealized gains or losses included in other comprehensive income.

Inventories Crude oil, petroleum products and chemicals are generally stated at cost, using a Last-In, First-Out (LIFO) method. In the aggregate, these costs are below market. Materials, supplies and other inventories generally are stated at average cost.

Properties, Plant and Equipment The successful efforts method is used for oil and gas exploration and production activities. All costs for development wells, related plant and equipment, and proved mineral interests in oil and gas properties are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for wells that find commercially producible reserves that cannot be classified as proved, pending one or more of the following: (1) decisions on additional major capital expenditures, (2) the results of additional

FS-22

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

exploratory wells that are under way or firmly planned, and (3) securing final regulatory approvals for development. Otherwise, well costs are expensed if a determination as to whether proved reserves were found cannot be made within one year following completion of drilling. All other exploratory wells and costs are expensed.

Long-lived assets, including proved oil and gas properties, are assessed for possible impairment by comparing their carrying values with the undiscounted future net before-tax cash flows. Impaired assets are written down to their estimated fair values, generally their discounted future net before-tax cash flows. For proved oil and gas properties in the United States, the company generally performs the impairment review on an individual field basis. Outside the United States, reviews are performed on a country or concession basis. Impairment amounts are recorded as incremental depreciation expense in the period in which the event occurs.

Depreciation and depletion (including provisions for future abandonment and restoration costs) of all capitalized costs of proved oil and gas producing properties, except mineral interests, are expensed using the unit-of-production method by individual field as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual fields as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed.

Depreciation and depletion expenses for coal are determined using the unit-of-production method as the proved reserves are produced. The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method generally is used to depreciate international plant and equipment and to amortize all capitalized leased assets.

Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses and from sales as Other income.

Expenditures for maintenance, repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized.

Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Liabilities related to future remediation costs are recorded when environmental assessments and/or cleanups are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals are generally based on the company’s commitment to a formal plan of action, such as an approved remediation plan or the sale or disposal of an asset. For the company’s U.S. and Canadian marketing facilities, the accrual is based on the probability that a future remediation commitment will be required. For oil, gas and coal producing properties, a provision is made through depreciation expense for anticipated abandonment and restoration costs at the end of a property’s useful life.

For Superfund sites, the company records a liability for its share of costs when it has been named as a Potentially Responsible Party (PRP) and when an assessment or cleanup plan has been developed. This liability includes the company’s own portion of the costs and also the company’s portion of amounts for other PRPs when it is probable that they will not be able to pay their share of the cleanup obligation.

The company records the gross amount of its liability based on its best estimate of future costs using currently available technology and applying current regulations as well as the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured.

Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains or losses from currency translations are currently included in income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in the currency translation adjustment in stockholders’ equity.

Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which ChevronTexaco has an interest with other producers are generally recognized on the basis of the company’s net working interest (entitlement method).

Stock Compensation The company applies Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for stock options, and presents in Note 21 pro forma net income and earnings per share data as if the accounting prescribed by FAS No. 123, “Accounting for Stock-Based Compensation,” had been applied.

NOTE 2. TEXACO MERGER TRANSACTION

The following table presents summarized financial data for the combined company for periods prior to the merger.


		Nine months ended			Year ended
		September 30			December 31

Millions of dollars		2001			2000		1999

Revenues and other income




	Chevron	$	37,213		$	52,129	$	36,586




	Texaco¹		39,469			53,520		37,779




	Adjustments/eliminations²		8,103			13,481		11,348

ChevronTexaco		$	84,785		$	119,130	$	85,713

Net Income




	Chevron	$	4,092		$	5,185	$	2,070




	Texaco¹		2,214			2,542		1,177

	Net income, before extraordinary item	$	6,306		$	7,727	$	3,247

	Extraordinary loss net of income tax³		(496	)		—		—

ChevronTexaco		$	5,810		$	7,727	$	3,247

¹		Includes certain reclassification adjustments to conform to historic Chevron presentation.




²		Consolidation of former equity operations and intercompany eliminations.




³		Represents loss associated with the sale of the company’s interest in Equilon and Motiva.

FS-23

Notes to Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 2. TEXACO MERGER TRANSACTION – Continued

At the time of the merger, each share of Texaco common stock was converted, on a tax-free basis, into the right to receive 0.77 shares of ChevronTexaco common stock. Approximately 425 million additional shares of common stock were issued, representing about 40 percent of the outstanding ChevronTexaco common stock after the merger.

As a condition of approving the merger, the U.S. Federal Trade Commission (FTC) required the divestment of certain Texaco assets: Texaco’s investments in its U.S. refining, marketing and transportation affiliates, Equilon Enterprises LLC (Equilon) and Motiva Enterprises LLC (Motiva), as well as other interests in U.S. natural gas processing and transportation facilities and general aviation fuel marketing.

Also at the time of the merger, Texaco placed its interests in Equilon and Motiva in trust, as required by the FTC. Because the company no longer exercised significant influence over these investments, the associated accounting method was changed from equity to the cost basis.

NOTE 3. EXTRAORDINARY ITEM

Net income for 2001 included a loss of $643, net of a tax benefit of $144, ($0.61 per common share – diluted), related to the disposition of assets that were required as a condition of the FTC approval of the merger and other assets that were made duplicative by the merger. The after-tax loss on these dispositions was reported as an extraordinary item in accordance with pooling-of-interests accounting requirements.

Included in the total after-tax loss was a loss of $564 connected with the sale of interests in Equilon and Motiva. Proceeds from the sale, which closed in February 2002, were approximately $2,200.

For both assets that were being sold by order of the FTC and other assets that were being disposed of because they were made duplicative by the merger, the total net book value at year-end 2001 was $2,181. This amount was included in “Current assets” on the Consolidated Balance Sheet as “Assets held for sale - merger related.” Net income for 2001 associated with all such assets being sold as a result of the merger was approximately $375.

NOTE 4. EMPLOYEE TERMINATION BENEFITS AND OTHER RESTRUCTURING COSTS

The company recorded before-tax charges of $1,563 in 2001 for merger-related expenses, which included: employee severance benefits; incremental pension and medical plan costs associated with work force reductions; legal, accounting, SEC filing and investment banker fees; employee and office relocations; and costs for the elimination of redundant facilities and operations.

Included in the 2001 charges were accruals of $891 for employee termination benefits for approximately 4,500 employees and other merger-related expenses that would not benefit future periods. Payments against these accruals during the year were $105. Approximately 1,400 employees had terminated by year-end. The year-end accrual balance of $786 is expected to be mostly extinguished by early 2003, as certain terminating employees are eligible to delay their separation payments one year or more. At year-end 2001, approximately $275 of the accrual balance was classified as long term.

Accrual balances for pre-merger restructuring costs had all been extinguished before the end of 2001.

NOTE 5. SPECIAL ITEMS, MERGER EFFECTS AND OTHER FINANCIAL INFORMATION

Net income is affected by transactions that are unrelated to or are not necessarily representative of the company’s ongoing operations for the periods presented. These transactions, defined by management and designated “special items, merger effects and extraordinary items,” can obscure the underlying results of operations for a year as well as affect comparability of results between years.

Listed in the following table are categories of these items and their net increase (decrease) to net income, after related tax effects.


				Year ended December 31

				2001			2000			1999

Special Items




Asset write-offs and revaluations




	Exploration and production




		Impairments – U.S.		$	(1,168	)	$	(176	)	$	(204	)




			– International		(247	)		—			—




	Refining, marketing and transportation




		Impairments – U.S.			—			—			(76	)




			– International		(46	)		(112	)		—




	Chemicals




		Manufacturing facility impairment – U.S.			(32	)		(90	)		—




		Other asset write-offs			(64	)		—			(43	)




	All other




		Mining asset write-off			(152	)		—			—




		Information technology and other assets			—			—			(54	)

					(1,709	)		(378	)		(377	)

Asset dispositions, net




	Oil and gas assets – U.S.				49			(107	)		—




	Oil and gas assets – International				—			80			—




	Real estate and other				—			99			87




	Pipeline interests				—			—			75




	Coal assets				—			—			60




	Equity affiliate interest – Japan				—			—			(111	)

					49			72			111

Prior-year tax adjustments					(5	)		107			228

Environmental remediation provisions, net					(78	)		(264	)		(40	)

Pre-merger restructurings and reorganizations					—			—			(257	)

Other, net




	Dynegy equity adjustment				—			77			—




	Litigation and regulatory issues				—			(62	)		104




	Tax benefits on asset sales				—			70			40

					—			85			144

Total special items				$	(1,743	)	$	(378	)	$	(191	)




Merger Effects




Merger-related expenses					(1,136	)		—			—




Extraordinary loss on merger-related asset sales					(643	)		—			—

Total special items and merger effects				$	(3,522	)	$	(378	)	$	(191	)

FS-24

NOTE 5. SPECIAL ITEMS, MERGER EFFECTS AND OTHER FINANCIAL INFORMATION – Continued

In accordance with its policy, the company recorded impairments of assets to be held and used when changes in circumstances – primarily related to lower oil and gas prices, downward revisions of reserves and changes in the use of the assets – indicated that the carrying values of the assets could not be recovered through estimated future before-tax undiscounted cash flows. 2001 included a $1,022 impairment of the Midway Sunset Field in California – the result of a write-down in proved oil reserve quantities – upon determination of a lower-than-projected oil recovery from the field’s steam injection process. There was also a $247 impairment of the LL-652 Field in Venezuela in 2001 – as slower-than-expected reservoir repressurization resulted in a reduction in the projected volumes of oil recoverable during the company’s remaining contract period of operation. Asset impairments included in “Asset write-offs and revaluations” were for assets held for use, except for U.S. coal assets in 1999. In late 1999, these assets were reclassified to “held for use” upon cessation of negotiations with potential buyers.

The aggregate income statement effects from special items are reflected in the following table, including ChevronTexaco’s proportionate share of special items related to equity affiliates.


	Year ended December 31

	2001			2000			1999

Revenues and other income




Income from equity affiliates	$	(123	)	$	(141	)	$	(212	)




Other income		84			356			318

Total revenues and other income		(39	)		215			106

Costs and other deductions




Operating expenses		25			394			280




Selling, general and administrative expenses		139			94			(81	)




Exploration expenses		—			—			1




Depreciation, depletion and amortization		2,294			561			397




Merger-related expenses		1,563			—			—




Taxes other than on income		12			—			—




Interest and debt expense		—			4			—




Minority interest		—			(9	)		—

Total costs and other deductions		4,033			1,044			597

Income before income tax expense		(4,072	)		(829	)		(491	)




Income tax expense		(1,193	)		(451	)		(300	)

Net income before extraordinary item	$	(2,879	)	$	(378	)	$	(191	)




Extraordinary loss, net of income tax		(643	)		—			—

Net income	$	(3,522	)	$	(378	)	$	(191	)

Other financial information is as follows:


	Year ended December 31

	2001		2000		1999

Total financing interest and debt costs	$	955	$	1,218	$	1,170




Less: capitalized interest		122		108		38

Interest and debt expense	$	833	$	1,110	$	1,132

Research and development expenses	$	209	$	211	$	226




Foreign currency gains (losses)*	$	191	$	182	$	(15	)

Includes $12, $66 and $(32) in 2001, 2000 and 1999, respectively, for the company’s share of equity affiliates’ foreign currency gains (losses).

The excess of market value over the carrying value of inventories for which the LIFO method is used was $1,580, $2,339 and $1,169 at December 31, 2001, 2000 and 1999, respectively. Market value is generally based on average acquisition costs for the year. In 2000, certain inventories were recorded at market, which was lower than LIFO carrying value. Adjustments to market reduced net income $4 in 2000. In 2001 and 1999, the market valuation adjustment reserves established in prior years were eliminated as market prices improved and the associated physical units of inventory were sold. Elimination of these reserves increased net income by $4 and $170 in 2001 and 1999, respectively.

NOTE 6. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS

“Net decrease in operating working capital” is composed of the following:


	Year ended December 31

	2001			2000			1999

Decrease (increase) in accounts and notes receivable	$	2,472		$	(2,162	)	$	(2,057	)




(Increase) decrease in inventories		(294	)		120			32




(Increase) decrease in prepaid expenses and other current assets		(211	)		73			(61	)




(Decrease) increase in accounts payable and accrued liabilities		(742	)		1,327			1,718




(Decrease) increase in income and other taxes payable		(582	)		733			634

Net decrease in operating working capital	$	643		$	91		$	266

Net cash provided by operating activities includes the following cash payments for interest and income taxes:




Interest paid on debt (net of capitalized interest)	$	873		$	1,095		$	1,060




Income taxes paid	$	5,465		$	4,883		$	1,868

Net (purchases) sales of marketable securities consists of the following gross amounts:




Marketable securities purchased	$	(2,848	)	$	(6,671	)	$	(3,255	)




Marketable securities sold		2,665			6,751			3,852

Net (purchases) sales of marketable securities	$	(183	)	$	80		$	597

The major components of “Capital expenditures” and the reconciliation of this amount to the capital and exploratory expenditures, excluding equity in affiliates, presented in the MD&A are detailed in the following table.

FS-25

Notes to Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 6. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS – Continued


	Year ended December 31

	2001			2000			1999

Additions to properties, plant and equipment¹	$	6,445		$	6,173		$	8,125




Additions to investments		2,902	²		1,118			393




Current year dry-hole expenditures		418			402			475




Payments for other liabilities and assets, net		(52	)		(64	)		(1,098	)³

Capital expenditures		9,713			7,629			7,895




Expensed exploration expenditures		393			487			489




Payments of long-term debt and other financing obligations, net		210	⁴		175			648	⁵

Capital and exploratory expenditures, excluding equity affiliates	$	10,316		$	8,291		$	9,032

¹		2001 net of a noncash reclassification of $63.




²		Includes $1,500 for investment in Dynegy preferred stock.




³		Includes liabilities assumed in acquisitions of Rutherford-Moran Oil Corporation and Petrolera Argentina San Jorge S.A.




⁴		Represents a deferred payment related to 1993 acquisition of an interest in the Tengizchevroil joint venture.




⁵		Includes obligations assumed in acquisition of Rutherford-Moran Oil Corporation and other capital lease additions.

The Consolidated Statement of Cash Flows excludes the following significant noncash transaction:

In 2000, Chevron contributed $2,800 of net noncash assets to Chevron Phillips Chemical Company LLC (CPChem). The investment is accounted for under the equity method.

NOTE 7. SUMMARIZED FINANCIAL DATA – CHEVRON U.S.A. INC.

Chevron U.S.A. Inc. (CUSA), is a major subsidiary of ChevronTexaco Corporation. CUSA owns, manages and operates on its own behalf or on behalf of other ChevronTexaco subsidiaries, the U.S. integrated petroleum operations, excluding ChevronTexaco’s investments in Equilon and Motiva, which were sold in February 2002, and most of the pipeline operations of ChevronTexaco. CUSA and its subsidiaries and affiliates manage and operate most of ChevronTexaco’s U.S. businesses and assets related to the exploration and production of crude oil, natural gas and natural gas liquids and also those associated with refining, marketing, supply and distribution of products derived from petroleum, other than natural gas liquids. CUSA also holds ChevronTexaco’s investment in CPChem. Summarized financial information for CUSA and its consolidated subsidiaries is presented below.


	Year ended December 31

	2001		2000*		1999*

Sales and other operating revenues	$	37,033	$	40,729	$	28,957




Total costs and other deductions		34,771		38,047		28,644




Net income		1,802		2,336		885

Certain reclassifications were made to conform to the 2001 presentation.


	At December 31

	2001		2000

Current assets	$	2,888	$	4,396




Other assets		20,795		20,738




Current liabilities		4,344		4,094




Other liabilities		9,797		10,251




Net equity		9,542		10,789

Memo: Total Debt	$	6,272	$	6,728

NOTE 8. SUMMARIZED FINANCIAL DATA – CHEVRON TRANSPORT CORPORATION LTD.

Chevron Transport Corporation Ltd. (CTC), incorporated in the Bermuda Islands, 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 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:


	Year ended December 31

	2001		2000			1999

Sales and other operating revenues	$	859	$	728		$	504




Total costs and other deductions		793		777			572




Net income (loss)		67		(47	)		(50	)


	At December 31

	2001		2000

Current assets	$	196	$	205




Other assets		527		530




Current liabilities		280		309




Other liabilities		311		361




Net equity		132		65

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at December 31, 2001.

NOTE 9. STOCKHOLDERS’ EQUITY

Retained earnings at December 31, 2001 and 2000, included approximately $2,001 and $2,300, respectively, for the company’s share of undistributed earnings of equity affiliates. The interests in Equilon and Motiva were placed in trust at the time of the merger, and ChevronTexaco no longer had significant influence over the joint ventures. Accordingly, the method of accounting for these investments was changed in the fourth quarter 2001 from equity to cost basis.

Upon the merger of Chevron and Texaco, the authorized common stock of ChevronTexaco was increased from 2 billion shares of $0.75 par value to 4 billion shares of $0.75 par value. Under the terms of the merger agreement, approximately 425 million shares of ChevronTexaco common stock were issued in exchange for all of the outstanding shares of Texaco common stock based upon an exchange ratio of 0.77 of a ChevronTexaco share for each Texaco

FS-26

NOTE 9. STOCKHOLDERS’ EQUITY – Continued

share. Texaco’s common stock held in treasury was canceled at the effective time of the merger.

In 1998, in connection with the renewal of Chevron’s Stockholder Rights Plan, Chevron declared a dividend distribution on each outstanding share of its common stock of one Right to purchase participating preferred stock. Since this distribution in 1998, all newly issued shares of the corporation’s common stock have been accompanied by a preferred stock purchase Right, including the shares issued in connection with the merger between Chevron and Texaco. Following the merger, the Chevron Stockholder Rights Plan has continued as the Stockholder Rights plan of ChevronTexaco. The Rights issued under the plan become exercisable, unless redeemed earlier by ChevronTexaco, if a person or group acquires or obtains the right to acquire 10 percent or more of the outstanding shares of common stock or commences a tender or exchange offer that would result in that person or group acquiring 10 percent or more of the outstanding shares of common stock, either event occurring without the prior consent of ChevronTexaco. The ChevronTexaco Series A Participating Preferred Stock that the holder of a Right is entitled to receive and the purchase price payable upon exercise of the ChevronTexaco Right are both subject to adjustment. The person or group who acquired 10 percent or more of the outstanding shares of common stock without the prior consent of ChevronTexaco would not be entitled to this purchase.

The Rights will expire in November 2008, or they may be redeemed by the company at 1 cent per Right prior to that date. The Rights do not have voting or dividend rights and until they become exercisable, have no dilutive effect on the earnings per share of the company. Five million shares of the company’s preferred stock have been designated Series A Participating Preferred Stock and reserved for issuance upon exercise of the Rights. No event during 2001 made the Rights exercisable.

In 1989, Texaco established a similar stockholder rights plan and reserved and designated 3 million shares as Series D for issuance upon exercise of the Rights. Prior to the merger, the Rights were not exercisable nor did they become exercisable upon the merger. Immediately after the merger, the Texaco Rights and Series D Junior Participating Preferred Stock were delisted and the Texaco stockholder rights plan was terminated.

During 2000 and until June 2001, there were 1,200 shares of Texaco cumulative variable rate preferred stock, called Market Auction Preferred Shares (MAPS), outstanding with an aggregate value of $300. The MAPS were redeemed in June 2001, at a liquidation preference of $250,000 per share, plus premium and accrued and unpaid dividends.

At December 31, 2001, 30 million shares of ChevronTexaco’s authorized but unissued common stock were reserved for issuance under the ChevronTexaco Corporation Long-Term Incentive Plan (LTIP), which was approved by the stockholders in 1990. To date, all of the plan’s common stock requirements have been met from the company’s treasury stock, and there have been no issuances of reserved shares.

NOTE 10. FINANCIAL AND DERIVATIVE INSTRUMENTS

Commodity Derivative Instruments ChevronTexaco is exposed to market risks related to price volatility of crude oil, refined products, natural gas and refinery feedstock.

The company uses derivative commodity instruments to manage this exposure on a small portion of its activity including: firm commitments and anticipated transactions for the purchase or sale of crude oil, feedstock purchases for company refineries, crude oil and refined products inventories, and fixed price contracts to sell natural gas and natural gas liquids.

The company also uses derivative commodity instruments for limited trading purposes.

The company maintains a policy of requiring that an International Swaps and Derivatives Association Master Agreement govern derivative contracts with certain counterparties to mitigate credit risk. Depending on the nature of the derivative transaction, bilateral collateral arrangements may also be required. When the company is engaged in more than one outstanding derivative transaction with the same counterparty and also has a legally enforceable master netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of the company’s credit risk. It is the company’s policy to use other master netting agreements with all counterparties with which it conducts significant transactions.

The fair values of the outstanding contracts are reported on the Consolidated Balance Sheet as “Accounts and notes receivable,” “Accounts payable,” “Long-term receivables – net,” and “Deferred credits and other noncurrent obligations.” Gains and losses on the company’s risk management activities are reported as either “Sales and other operating revenues” or “Purchased crude oil and products,” whereas trading gains and losses are reported as “Other income.” These activities are reported under “Operating activities” in the Consolidated Statement of Cash Flows.

Foreign Currency The company enters into forward exchange contracts, generally with terms of 180 days or less, to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments, forecasted to occur within 180 days. The forward exchange contracts are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.

The fair values of the outstanding contracts are reported on the Consolidated Balance Sheet as “Accounts and notes receivable” or “Accounts payable,” with gains and losses reported as “Other income.” These activities are reported under “Operating activities” in the Consolidated Statement of Cash Flows.

Interest Rates The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements are based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts. Interest rate swaps related to a portion of the company’s fixed-rate debt are accounted for as fair value hedges, whereas interest rate swaps related to a portion of the company’s floating-rate debt are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.

FS-27

Notes to Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 10. FINANCIAL AND DERIVATIVE INSTRUMENTS - Continued

During 2001, no new swaps were initiated in connection with debt issues in the year. At year-end 2001, the weighted average maturity of interest rate swaps was approximately five years.

Fair values of the interest rate swaps are reported on the Consolidated Balance Sheet as “Accounts and notes receivables” or “Accounts payable,” with gains and losses reported directly in income as part of “Interest and debt expense.” These activities are reported under “Operating activities” in the Consolidated Statement of Cash Flows.

Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables. The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings. This diversified investment policy limits the company’s exposure both to credit risk and to concentrations of credit risk. Similar standards of diversity and creditworthiness are applied to the company’s counterparties in derivative instruments.

The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s broad customer base worldwide. As a consequence, concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. Letters of credit or negotiated contracts, when the financial strength of a customer is not considered sufficient, are the principal securities obtained to support lines of credit.

Fair Value Fair values are derived either from quoted market prices or, if not available, the present value of the expected cash flows. The fair values reflect the cash that would have been received or paid if the instruments were settled at year-end.

Long-term debt of $6,599 and $8,870 had estimated fair values of $7,097 and $8,991 at December 31, 2001 and 2000, respectively.

The company holds cash equivalents and U.S. dollar marketable securities in domestic and offshore portfolios. Eurodollar bonds, floating-rate notes, time deposits and commercial paper are the primary instruments held. Cash equivalents and marketable securities had fair values of $2,449 and $2,543 at December 31, 2001 and 2000, respectively. Of these balances, $1,446 and $1,630 at the respective year-ends were classified as cash equivalents that had average maturities under 90 days. The remainder, classified as marketable securities, had average maturities of approximately 3.6 years.

The company’s $1,500 investment in redeemable, convertible preferred stock of its Dynegy affiliate is carried at fair value.

NOTE 11. OPERATING SEGMENTS AND GEOGRAPHIC DATA

ChevronTexaco separately manages its exploration and production; refining, marketing and transportation; and chemicals businesses. The company’s primary country of operation is the United States, its country of domicile. The remainder of the company’s operations is reported as International (outside the United States).

Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments; instead, operating segments are billed only for direct corporate services. Nonbillable costs and merger effects remain as corporate expenses. After-tax segment income (loss) is presented in the following table.


	Year ended December 31

	2001			2000			1999

Exploration and Production




United States	$	1,779		$	3,453		$	1,133




International		2,533			3,702			1,450

Total Exploration and Production		4,312			7,155			2,583

Refining, Marketing and Transportation




United States		1,254			721			551




International		560			414			546

Total Refining, Marketing and Transportation		1,814			1,135			1,097

Chemicals




United States		(186	)		(31	)		44




International		58			71			65

Total Chemicals		(128	)		40			109

Total Segment Income		5,998			8,330			3,789




Merger effects	$	(1,779	)		—			—




Interest expense		(552	)		(766	)		(779	)




Interest income		147			139			81




Other		(526	)		24			156

Net Income	$	3,288		$	7,727		$	3,247

Segment Assets Segment assets do not include intercompany investments or intercompany receivables. “All Other” assets consist primarily of worldwide cash and marketable securities, real estate, information systems, the investment in Dynegy Inc., coal mining operations, power and gasification operations, and technology investments and merger-related assets held for sale at year-end 2001. Segment assets at year-end 2001 and 2000 follow.

FS-28

NOTE 11. OPERATING SEGMENTS AND GEOGRAPHIC DATA — Continued


	At December 31

	2001		2000

Exploration and Production




United States	$	12,718	$	15,216




International		24,177		22,463

Total Exploration and Production		36,895		37,679

Refining, Marketing and Transportation




United States		8,902		12,118




International		16,426		17,034

Total Refining, Marketing and Transportation		25,328		29,152

Chemicals




United States		2,059		2,350




International		701		727

Total Chemicals		2,760		3,077

Total Segment Assets		64,983		69,908

All Other




United States		8,950		5,361




International		3,639		2,352

Total All Other		12,589		7,713

Total Assets — United States		32,629		35,045




Total Assets — International		44,943		42,576

Total Assets	$	77,572	$	77,621

Segment Sales and Other Operating Revenues Revenues for the exploration and production segment are derived primarily from the production of crude oil and natural gas. Revenues for the refining, marketing and transportation segment are derived from the refining and marketing of petroleum products, such as gasoline, jet fuel, gas oils, kerosene, 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. Prior to the July 2000 formation of CPChem, chemicals segment revenues were derived from the manufacture and sale of petrochemicals, plastic resins, and lube oil and fuel additives. Subsequent to the formation of the joint venture, only revenues from the manufacture and sale of lube oil and fuel additives were included.

“All Other” activities include corporate administrative costs, worldwide cash management and debt financing activities, coal mining operations, power and gasification operations, technology investments, insurance operations and real estate activities. Other than the United States, the only country where ChevronTexaco generates significant revenues is the United Kingdom, which amounted to $10,350, $12,101 and $9,650 in 2001, 2000 and 1999, respectively. Sales revenues are based on the origin of the sale.

Reportable operating segment “Sales and other operating revenues,” including internal transfers, for the years 2001, 2000 and 1999 are presented in the following table. Sales from the transfer of products between segments are at prices that approximate market prices.


		Year ended December 31

		2001			2000			1999

Exploration and Production




United States		$	12,724		$	13,927		$	7,819




	Intersegment		3,167			3,542			2,205

	Total United States		15,891			17,469			10,024

International			9,126			9,052			6,202




	Intersegment		7,376			6,189			3,800

	Total International		16,502			15,241			10,002

Total Exploration and Production			32,393			32,710			20,026

Refining, Marketing and Transportation




United States			29,294			31,926			20,468




	Excise taxes		3,954			3,837			3,702




	Intersegment		392			414			476

	Total United States		33,640			36,177			24,646

International			45,248			52,501			38,993




	Excise taxes		2,580			2,737			2,842




	Intersegment		452			930			160

	Total International		48,280			56,168			41,995

Total Refining, Marketing and Transportation			81,920			92,345			66,641

Chemicals




United States			335			1,985			2,791




	Excise taxes		—			1			2




	Intersegment		89			137			162

	Total United States		424			2,123			2,955

International			670			701			686




	Excise taxes		12			26			28




	Intersegment		65			—			171

	Total International		747			727			885

Total Chemicals			1,171			2,850			3,840

All Other




United States			429			403			456




	Intersegment		60			90			55

	Total United States		489			493			511

International			37			(1	)		15




	Intersegment		9			19			12

	Total International		46			18			27

Total All Other			535			511			538

Segment Sales and Other Operating Revenues




	United States		50,444			56,262			38,136




	International		65,575			72,154			52,909

Total Segment Sales and Other Operating Revenues			116,019			128,416			91,045

Elimination of Intersegment Sales			(11,610	)		(11,321	)		(7,041	)

Total Sales and Other Operating Revenues		$	104,409		$	117,095		$	84,004

Segment Income Taxes Segment income tax expenses for the years 2001, 2000 and 1999 are as follows:

FS-29

Notes to Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 11. OPERATING SEGMENTS AND GEOGRAPHIC DATA — Continued


	Year ended December 31

	2001			2000			1999

Exploration and Production




United States	$	965		$	1,901		$	559




International		3,569			4,363			2,164

Total Exploration and Production		4,534			6,264			2,723

Refining, Marketing and Transportation




United States		744			383			279




International		260			152			175

Total Refining, Marketing and Transportation		1,004			535			454

Chemicals




United States		(78	)		31			(13	)




International		23			30			45

Total Chemicals		(55	)		61			32

All Other*		(1,123	)		(538	)		(644	)

Total Income Tax Expense*	$	4,360		$	6,322		$	2,565

Excludes tax of $144 for extraordinary item.

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 14. Information related to properties, plant and equipment by segment is contained in Note 15.

NOTE 12. LITIGATION

Chevron, Texaco and four other oil companies (refiners) filed suit in 1995 contesting the validity of a patent granted to Unocal Corporation (Unocal) for reformulated gasoline, which ChevronTexaco sells in California in certain months of the year. In March 2000, the U.S. Court of Appeals for the Federal Circuit upheld a September 1998 District Court decision that Unocal’s patent was valid and enforceable and assessed damages of 5.75 cents per gallon for gasoline produced in infringement of the patent. In May 2000, the Federal Circuit Court denied a petition for rehearing with the U.S. Court of Appeals for the Federal Circuit filed by the refiners in this case. The refiners petitioned the U.S. Supreme Court and, in February 2001, the Supreme Court denied the petition to review the lower court’s ruling and the case was remanded to the District Court for an accounting of all infringing gasoline produced from August 1, 1996, to September 30, 2000. The District Court granted Unocal’s motion for summary judgment requesting an accounting and denied the refiners’ motion to stay the proceedings and vacate the accounting order. However, the judge presiding over this case recused himself before entering a final judgment and a new judge was assigned. Additionally, in May 2001, the U.S. Patent Office (USPO) granted the refiners’ petition to re-examine the validity of Unocal’s patent and, in February 2002, the USPO ruled the patent invalid. Unocal has two months to respond to the USPO ruling. The Federal Trade Commission has also announced that it is investigating whether Unocal’s failure to disclose to the California Air Resources Board that it had filed a patent application was unfair competition, which may make Unocal’s patent unenforceable.

If Unocal’s patent ultimately is upheld and is enforceable, the company’s financial exposure includes royalties, plus interest, for production of gasoline that is proved to have infringed the patent. Chevron and Texaco, as well as Texaco’s former affiliates Equilon and Motiva, have been accruing in the normal course of business any future estimated liability for potential infringement of the patent covered by the trial court’s ruling. In 2000, Chevron and Texaco made payments to Unocal totaling approximately $28 for the original court ruling, including interest and fees.

Unocal has obtained additional patents for alternate formulations that could affect a larger share of U.S. gasoline production. ChevronTexaco believes these additional patents are invalid and unenforceable. However, if such patents are ultimately upheld, the competitive and financial effects on the company’s refining and marketing operations, while presently indeterminable, could be material.

Another issue involving the company is the petroleum industry’s use of methyl tertiary-butyl ether (MTBE) as a gasoline additive and its potential environmental impact through seepage into groundwater. Along with other oil companies, the company is a party to lawsuits and claims related to the use of the chemical MTBE in certain oxygenated gasolines. These actions may require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. Costs to the company related to these lawsuits and claims are not currently determinable. ChevronTexaco continues the use of MTBE in gasoline it sells in certain areas. The state of California has directed that MTBE be phased out of the manufacturing process by the end of 2002.

NOTE 13. LEASE COMMITMENTS

Certain noncancelable leases are classified as capital leases, and the leased assets are included as part of “Properties, plant and equipment, at cost.” Such leasing arrangements involve tanker charters, crude oil production and processing equipment, service stations and other facilities. Other leases are classified as operating leases and are not capitalized. The payments on such leases are recorded as expense. Details of the capitalized leased assets are as follows:


		At December 31

		2001		2000

Exploration and production		$	172	$	223




Refining, marketing and transportation			848		851

	Total		1,020		1,074




Less: accumulated amortization			567		587

Net capitalized leased assets		$	453	$	487

Rental expenses incurred for operating leases during 2001, 2000 and 1999 were as follows:

FS-30

NOTE 13. LEASE COMMITMENTS — Continued


		Year ended December 31

		2001		2000		1999

Minimum rentals		$	1,132	$	1,062	$	804




Contingent rentals			14		35		16

	Total		1,146		1,097		820




Less: sublease rental income			76		77		73

Net rental expense		$	1,070	$	1,020	$	747

Contingent rentals are based on factors other than the passage of time, principally sales volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, renewal options ranging from one to 25 years, and/or options to purchase the leased property during or at the end of the initial or renewal lease period for the fair market value or other specified amount at that time.

At December 31, 2001, the estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases, which at inception had a noncancelable term of more than one year, were as follows:


			At December 31

			Operating		Capital
			Leases		Leases

	Year: 2002		$	692	$	80




		2003		314		111




		2004		301		54




		2005		266		49




		2006		237		47




		Thereafter		731		613

Total			$	2,541	$	954

Less: amounts representing interest and executory costs						323

Net present values						631




Less: capital lease obligations included in short-term debt						346

Long-term capital lease obligations					$	285

NOTE 14. INVESTMENTS AND ADVANCES

Descriptions of major affiliates during 2001 are as follows:

Tengizchevroil Tengizchevroil (TCO) is a joint venture formed in 1993 to develop the Tengiz and Korolev oil fields in Kazakhstan over a 40-year period. Chevron’s ownership was 45 percent during 1999 and 2000. In January 2001, the company purchased an additional 5 percent interest. Upon formation of the joint venture, the company incurred an obligation of $420, payable to the Republic of Kazakhstan upon attainment of a dedicated export system with the capability of the greater of 260,000 barrels of oil per day or TCO’s production capacity. As a part of the January transaction, the company paid $210 of the $420 obligation. The $420 was also included in the carrying value of the original investment, as the company believed, beyond a reasonable doubt, that its full payment would be made.

Equilon Enterprises LLC Effective January 1, 1998, Texaco and Shell Oil Company (Shell) formed Equilon, a Delaware limited liability company. Equilon is a joint venture that combined major elements of those companies’ western and midwestern U.S. refining and marketing businesses and their nationwide trading, transportation and lubricants businesses. The company’s 44 percent ownership interest in Equilon was placed in trust on October 9, 2001, as required by the FTC. The trust completed the disposition of the company’s investment in Equilon in February 2002.

Because Equilon is a limited liability company, ChevronTexaco recorded the provision for income taxes and related income tax liability applicable to its share of the venture’s income separately in its consolidated financial statements.

See Note 2 for additional information on Equilon.

Motiva Enterprises LLC Effective July 1, 1998, Texaco, Shell and Saudi Refining Inc., a corporate affiliate of Saudi Aramco, formed Motiva, a Delaware limited liability company. Motiva is a joint venture that combined the East and Gulf Coast U.S. refining and marketing businesses of Shell and Star Enterprise (Star). Star, in turn, was a joint venture owned 50 percent each by Texaco and Saudi Refining Inc.

Under the terms of the Limited Liability Company Agreement for Motiva, the ownership in Motiva is subject to annual adjustment through year-end 2005, based on the performance of the assets contributed to Motiva. Accordingly, the company’s initial 32.5 percent ownership in Motiva was adjusted effective as of January 1, 2000, to just under 31 percent. At January 1, 2001, the company’s ownership percentage was adjusted to 35 percent. The company’s ownership interest in Motiva was placed in trust on October 9, 2001, as required by the FTC. The trust completed the disposition of the company’s investment in Motiva in February 2002.

Because Motiva is a limited liability company, ChevronTexaco recorded the provision for income taxes and related income tax liability applicable to its share of the venture’s income separately in its consolidated financial statements.

See Note 2 for additional information on Motiva.

LG-Caltex Corporation ChevronTexaco owns 50 percent of LG-Caltex, a joint venture formed in 1967 between the LG Group and Caltex, originally incorporated as Honam Oil Refinery Company Limited, to engage in importing, refining and marketing of petroleum products in Korea.

Star Petroleum Refining Company, Ltd. ChevronTexaco has a 64 percent equity ownership interest in Star Petroleum Refining Company Limited (SPRC), which owns the Star refinery at Ma Ta Phut, Thailand. The Thai national petroleum company owns the remaining 36 percent of SPRC.

Caltex Australia Ltd. ChevronTexaco has a 50 percent equity ownership interest in Caltex Australia Limited, which is the largest oil company in Australia. The remaining 50 percent of Caltex Australia is publicly owned.

Chevron Phillips Chemical Company LLC ChevronTexaco owns 50 percent of CPChem, formed in July 2000 when Chevron merged most of its petrochemicals businesses with those of Phillips Petroleum Company. Because CPChem is a limited liability company, ChevronTexaco records the provision for income taxes and related tax liability applicable to its share of the venture’s income separately in its consolidated financial statements.

FS-31

Notes to Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 14. INVESTMENTS AND ADVANCES — Continued

Dynegy Inc. Dynegy is a gatherer, processor, transporter and marketer of energy products in North America and the United Kingdom. These products include natural gas, natural gas liquids, crude oil and electricity. In 2001, ChevronTexaco exercised its preemptive rights and acquired a further 1.2 million shares of Dynegy’s common stock for $40.8. This additional investment maintained the company’s equity ownership in Dynegy at approximately 26.5 percent. Also, in 2001, ChevronTexaco invested $1,500 in Dynegy redeemable, convertible preferred stock. The market value of ChevronTexaco’s share of Dynegy common stock at December 31, 2001, was $2,206, based on equivalent closing market prices. The fair value of the redeemable convertible preferred stock was $1,500.

“Sales and other operating revenues” on the Consolidated Statement of Income include $13,868, $15,741 and $10,068 with major affiliated companies for 2001, 2000 and 1999. “Purchased crude oil and products” include $3,859, $4,824 and $2,837 with major affiliated companies for 2001, 2000 and 1999.

“Accounts and notes receivable” on the Consolidated Balance Sheet include $481 and $1,392 due from affiliated companies at December 31, 2001 and 2000, respectively. “Accounts payable” include $168 and $313 due to major affiliated companies at December 31, 2001 and 2000, respectively. These 2001 amounts exclude balances with Equilon and Motiva.

Equity in earnings, together with investments in and advances to companies accounted for using the equity method, and other investments accounted for at or below cost, are as follows:


		Investments and Advances				Equity in Earnings
		At December 31				Year ended December 31

		2001		2000		2001			2000			1999

Exploration and Production




	Tengizchevroil	$	2,459	$	1,857	$	332		$	376		$	177




	Other		808		550		205			163			98

	Total Exploration and Production		3,267		2,407		537			539			275

Refining, Marketing and Transportation




	Equilon*		—		1,724		274			151			219




	Motiva*		—		743		276			154			(5	)




	LG-Caltex Oil Corporation		1,491		1,468		60			80			310




	Caspian Pipeline Consortium		928		587		38			22			4




	Star Petroleum Refining Company Ltd.		394		337		(56	)		(4	)		(27	)




	Caltex Australia Limited		267		253		16			13			(48	)




	Other		755		680		92			117			93

Total Refining, Marketing and Transportation			3,835		5,792		700			533			546

Chemicals




	Chevron Phillips Chemical Company LLC		1,587		1,830		(229	)		(114	)		—




	Other		17		15		2			(9	)		1

	Total Chemicals		1,604		1,845		(227	)		(123	)		1

	Dynegy Inc.		2,628		929		188			127			51




	All Other		507		365		(54	)		1			23

	Total Equity Method	$	11,841	$	11,338	$	1,144		$	1,077		$	896

Other at or Below Cost			411		426

	Total Investments and Advances	$	12,252	$	11,764

Total U.S		$	5,370	$	6,323	$	693		$	562		$	419




Total International		$	6,882	$	5,441	$	451		$	515		$	477

Placed in trust at the time of the merger and accounting changed from the equity method to the cost basis. Interests were classified as “Assets held for sale — merger related” at December 31, 2001.

FS-32

NOTE 14. INVESTMENTS AND ADVANCES — Continued

The following table provides summarized financial information on a 100 percent basis for Equilon, Motiva and all other equity affiliates, as well as ChevronTexaco’s total share.


	Equilon*						Motiva*

YEAR ENDED DECEMBER 31	2001		2000		1999		2001		2000		1999

Total revenues	$	36,501	$	50,010	$	29,398	$	14,459	$	19,446	$	12,196




Income (loss) before income tax expense		604		228		347		771		461		(69	)




Net income (loss)		397		148		226		486		300		(45	)

AT DECEMBER 31

Current assets	$	—	$	3,134	$	3,426	$	—	$	1,381	$	1,271




Noncurrent assets		—		6,830		7,208		—		5,110		5,307




Current liabilities		—		4,587		4,853		—		1,150		1,278




Noncurrent liabilities		—		897		735		—		2,017		2,095

NET EQUITY	$	—	$	4,480	$	5,046	$	—	$	3,324	$	3,205

[Additional columns below]

[Continued from above table, first column(s) repeated]

Other Affiliates ChevronTexaco Share

YEAR ENDED DECEMBER 31 2001 2000 1999 2001 2000 1999

Total revenues
$ 69,549 $ 56,602 $ 33,772 $ 46,649 $ 48,925 $ 30,135

Income (loss) before income tax expense
646 2,420 1,566 1,430 1,230 925

Net income (loss)
(74 ) 1,689 1,326 1,144 1,077 896

AT DECEMBER 31

Current assets
$ 17,015 $ 18,442 $ 7,954 $ 5,922 $ 8,456 $ 4,992

Noncurrent assets
40,191 34,620 18,463 16,276 16,965 12,007

Current liabilities
14,688 16,109 7,665 4,757 7,820 5,615

Noncurrent liabilities
23,255 20,905 10,924 5,600 6,263 3,243

NET EQUITY
$ 19,263 $ 16,048 $ 7,828 $ 11,841 $ 11,338 $ 8,141

Accounted for under the equity method pre-merger, and the cost basis post-merger.

NOTE 15. PROPERTIES, PLANT AND EQUIPMENT¹


		At December 31

		Gross Investment at Cost						Net Investment

		2001		2000		1999		2001		2000		1999

Exploration and Production




	United States	$	38,157	$	37,342	$	39,772	$	10,560	$	12,093	$	12,773




	International		33,273		30,396		29,602		17,743		16,938		15,725

Total Exploration and Production			71,430		67,738		69,374		28,303		29,031		28,498

Refining, Marketing and Transportation




	United States		12,944		12,557		12,669		6,237		6,176		6,438




	International		11,386		10,986		11,736		6,700		6,718		7,251

Total Refining, Marketing and Transportation			24,330		23,543		24,405		12,937		12,894		13,689

Chemicals




	United States		602		610		3,689		321		342		2,354




	International		698		672		714		405		395		453

Total Chemicals			1,300		1,282		4,403		726		737		2,807





All Other³			2,883		3,005		2,809		1,267		1,657		1,493

Total United States			54,529		53,485		58,922		18,367		20,275		23,048




Total International			45,414		42,083		42,069		24,866		24,044		23,439

	Total	$	99,943	$	95,568	$	100,991	$	43,233	$	44,319	$	46,487

[Additional columns below]

[Continued from above table, first column(s) repeated]

Year ended December 31

Additions at Cost² Depreciation Expense

2001 2000 1999 2001 2000 1999

Exploration and Production

United States
$ 1,973 $ 1,931 $ 1,383 $ 3,508 $ 2,138 $ 1,932

International
2,900 3,019 4,934 2,085 1,787 1,546

Total Exploration and Production
4,873 4,950 6,317 5,593 3,925 3,478

Refining, Marketing and Transportation

United States
626 484 560 476 516 542

International
566 457 605 555 651 539

Total Refining, Marketing and Transportation
1,192 941 1,165 1,031 1,167 1,081

Chemicals

United States
10 78 326 22 77 174

International
31 42 59 19 18 20

Total Chemicals
41 120 385 41 95 194

All Other³
174 202 181 394 134 181

Total United States
2,780 2,695 2,447 4,391 2,825 2,824

Total International
3,500 3,518 5,601 2,668 2,496 2,110

Total
$ 6,280 $ 6,213 $ 8,048 $ 7,059 $ 5,321 $ 4,934

		1 Net of accumulated abandonment and restoration costs of $2,155, $2,259 and $2,397 at December 31, 2001, 2000 and 1999, respectively.




		2 Net of dry hole expense related to prior years’ expenditures of $228, $60 and $108 in 2001, 2000 and 1999, respectively.




		3 Primarily coal, real estate assets and management information systems.

FS-33

Notes to Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 16. TAXES


		Year ended December 31

		2001			2000		1999

Taxes on income




U.S. federal




	Current	$	946		$	1,238	$	307




	Deferred		(643	)		363		25




State and local			276			185		(50	)

	Total United States		579			1,786		282

International			3,764			4,378		2,285




	Current		3,764			4,378		2,285




	Deferred		17			158		(2	)

	Total International		3,781			4,536		2,283

Total taxes on income		$	4,360		$	6,322	$	2,565

The above table does not include a current U.S. tax benefit of $2 and a U.S. deferred tax benefit of $142 associated with the extraordinary item.

In 2001, before-tax income, including related corporate and other charges, for U.S. operations was $1,778, compared with $5,823 in 2000 and $1,738 in 1999. For international operations, before-tax income was $6,513, $8,226 and $4,074 in 2001, 2000 and 1999, respectively. U.S. federal income tax expense was reduced by $202, $165 and $156 in 2001, 2000 and 1999, respectively, for business tax credits.

The company’s effective income tax rate varied from the U.S. statutory federal income tax rate because of the following:


	Year ended December 31

	2001			2000			1999

U.S. statutory federal income tax rate		35.0	%		35.0	%		35.0	%




Effect of income taxes from international operations in excess of taxes at the U.S. statutory rate		19.0			11.0			16.7




State and local taxes on income, net of U.S. federal income tax benefit		2.2			0.9			(0.1	)




Prior-year tax adjustments		1.1			(0.6	)		(1.5	)




Tax credits		(2.4	)		(1.2	)		(2.7	)




Other		(1.7	)		0.2			(2.3	)

Consolidated companies		53.2			45.3			45.1




Effect of recording equity in income of certain affiliated companies on an after-tax basis		(0.6	)		(0.3	)		(1.0	)

Effective tax rate		52.6	%		45.0	%		44.1	%

The company records its deferred taxes on a tax-jurisdiction basis and classifies those net amounts as current or noncurrent based on the balance sheet classification of the related assets or liabilities.

The reported deferred tax balances are composed of the following:


		At December 31

		2001			2000

Deferred tax liabilities




	Properties, plant and equipment	$	7,478		$	7,224




	Inventory		50			—




	Investments and other		1,334			2,085

	Total deferred tax liabilities		8,862			9,309

Deferred tax assets




	Abandonment/environmental reserves		(913	)		(862	)




	Employee benefits		(863	)		(979	)




	Tax loss carryforwards		(611	)		(527	)




	AMT/other tax credits		(511	)		(943	)




	Inventory		—			(27	)




	Other accrued liabilities		(158	)		(43	)




	Miscellaneous		(2,164	)		(1,454	)

	Total deferred tax assets		(5,220	)		(4,835	)

Deferred tax assets valuation allowance			1,431			1,574

Total deferred taxes, net		$	5,073		$	6,048

The valuation allowance relates to foreign tax credit carryforwards, tax loss carryforwards and temporary differences that are not expected to be realized.

At December 31, 2001 and 2000, deferred taxes were classified in the Consolidated Balance Sheet as follows:


		At December 31

		2001			2000

Prepaid expenses and other current assets		$	(671	)	$	(327	)




Deferred charges and other assets			(399	)		(312	)




Federal and other taxes on income			11			—




Noncurrent deferred income taxes			6,132			6,687

	Total deferred income taxes, net	$	5,073		$	6,048

It is the company’s policy for subsidiaries included in the U.S. consolidated tax return to record income tax expense as though they filed separately, with the parent recording the adjustment to income tax expense for the effects of consolidation. Income taxes are accrued for retained earnings of international subsidiaries and corporate joint ventures intended to be remitted. Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely.

Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $9,003 at December 31, 2001. Substantially all of this amount represents earnings reinvested as part of the company’s ongoing business. It is not practical to estimate the amount of taxes that might be payable on the eventual remittance of such earnings. On remittance, certain countries impose withholding taxes that, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any.

FS-34

NOTE 16. TAXES — Continued

Taxes other than on income were as follows:


			Year ended December 31

			2001		2000		1999

Taxes other than on income




United States




	Excise taxes on products and merchandise		$	3,954	$	3,909	$	3,767




	Import duties and other levies			8		25		34




	Property and other miscellaneous taxes			410		345		365




	Payroll taxes			148		139		165




	Taxes on production			225		238		158

		Total United States		4,745		4,656		4,489

International




	Excise taxes on products and merchandise			2,592		2,692		2,262




	Import duties and other levies			7,461		8,073		8,352




	Property and other miscellaneous taxes			268		271		247




	Payroll taxes			79		69		77




	Taxes on production			11		66		14

		Total International		10,411		11,171		10,952

Total taxes other than on income			$	15,156	$	15,827	$	15,441

NOTE 17. SHORT-TERM DEBT


		At December 31

		2001			2000

Commercial paper*		$	8,664		$	4,258




Notes payable to banks and others with originating terms of one year or less			1,036			1,612




Current maturities of long-term debt			1,095			1,519




Current maturities of long-term capital leases			45			42




Redeemable long-term obligations




	Long-term debt		488			504




	Capital leases		301			302

	Subtotal		11,629			8,237




Reclassified to long-term debt			(3,200	)		(5,143	)

	Total short-term debt	$	8,429		$	3,094

Weighted-average interest rates at December 31, 2001 and 2000, were 1.99 percent and 6.57 percent, respectively, including the effect of interest rate swaps.

Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.

The company periodically enters into interest rate swaps on a portion of its short-term debt. See Note 10 for information concerning the company’s debt-related derivative activities.

Utilized lines of credit available for short-term financing totaled $210 at December 31, 2001.

At December 31, 2001, the company had $3,200 of committed credit facilities with banks worldwide, which permit the company to refinance short-term obligations on a long-term basis. The facilities support the company’s commercial paper borrowings. Interest on borrowings under the terms of specific agreements may be based on the London Interbank Offered Rate, the Reserve Adjusted Domestic Certificate of Deposit Rate or bank prime rate. No amounts were outstanding under these credit agreements during 2001 or at year-end.

At December 31, 2001 and 2000, the company classified $3,200 and $5,143, respectively, of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital in 2002, as the company has both the intent and ability to refinance this debt on a long-term basis.

NOTE 18. LONG-TERM DEBT

ChevronTexaco has three “shelf” registrations on file with the Securities and Exchange Commission that together would permit the issuance of $2,800 of debt securities pursuant to Rule 415 of the Securities Act of 1933.


			At December 31

			2001			2000

6.625% notes due 2004			$	499		$	499




8.11% amortizing notes due 2004				450			540




7.327% amortizing notes due 2014¹				430			430




5.5% note due 2009				393			392




7.45% notes due 2004				—			349




6% notes due 2005				299			299




9.75% debentures due 2020				250			250




3.5% convertible notes due 2004				—			203




5.7% notes due 2008				201			201




8.5% notes due 2003				200			200




7.75% debentures due 2033				199			199




8.625% debentures due 2031				199			199




8.625% debentures due 2032				199			199




8.375% debentures due 2022				199			198




7.5% debentures due 2043				198			198




6.875% debentures due 2023				196			196




7.09% notes due 2007				150			150




8.25% debentures due 2006				150			150




8.625% debentures due 2010				150			150




8.875% debentures due 2021				150			150




Medium-term notes, maturing from 2001 to 2043 (7.4%)²				360			1,081




Other foreign currency obligations (5.6%)²				193			1,095




Other long-term debt (4.2%)²				1,534			1,542

	Total including debt due within one year			6,599			8,870




		Debt due within one year		(1,095	)		(1,519	)




		Reclassified from short-term debt		3,200			5,143

Total long-term debt			$	8,704		$	12,494

		1 Guarantee of ESOP debt.




		2 Less than $150 individually; weighted-average interest rates at December 31, 2001.

Consolidated long-term debt maturing after December 31, 2001, is as follows: 2002 — $1,095; 2003 — $536; 2004 — $857; 2005 — $570; and 2006 — $195; after 2006 — $3,346.

See Note 10 for information concerning the company’s debt-related derivative activities.

FS-35

Notes to Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 19. NEW ACCOUNTING STANDARDS

The company adopted the Financial Accounting Standards Board (FASB) Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS 133), as amended by FAS 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment of FASB Statement No. 133,” effective January 1, 2001. The adoption of FAS 133 and FAS 138 did not have a significant impact on the company’s results of operations, financial position or liquidity.

In September 2000, the FASB issued Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities - A Replacement of FASB Statement No. 125” (FAS 140). FAS 140 is effective for transfers occurring after March 31, 2001, and for disclosures relating to securitization transactions and collateral for fiscal years ending after December 15, 2000. Adoption of FAS 140 had no significant effect on ChevronTexaco’s accounting or disclosures for the types of transactions in the scope of the new standard.

In June 2001, the FASB issued Statement No. 141, “Business Combinations” (FAS 141), Statement No. 142, “Goodwill and Other Intangible Assets” (FAS 142) and Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 141 is effective for all business combinations initiated after June 30, 2001, and for all business combinations accounted for using the purchase method for which the date of acquisition is July 1, 2001, or later. FAS 142 is effective for fiscal years beginning after December 15, 2001, except for goodwill and intangible assets acquired after June 30, 2001, which were immediately subject to the amortization and nonamortization provisions of the Statement. FAS 143 is effective for fiscal years beginning after June 15, 2002. Adoption of FAS 141 will have no effect on the company’s pooling-of-interests method of accounting for the Texaco merger transaction, but will affect future transactions. Similarly, adoption of FAS 142 may affect future transactions, but is not expected to have an effect on the company’s prior business combinations. FAS 143 differs in several significant respects from current accounting for asset retirements obligations under FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Adoption of FAS 143 will affect future accounting and reporting of the assets, liabilities and expenses related to these obligations. The magnitude of the effect has not yet been determined.

NOTE 20. EMPLOYEE BENEFIT PLANS

Pension Plans and Other Postretirement Benefits The company has defined benefit pension plans for most employees and provides for certain health care and life insurance plans for active and qualifying retired employees. For the pension plans, the company is required to satisfy the Employee Retirement Income Security Act minimum funding standard. The company’s annual contributions for medical and dental benefits are limited to the lesser of actual medical and dental claims or a defined fixed per-capita amount. Life insurance benefits are paid by the company, and annual contributions are based on actual plan experience. Unfunded pension and postretirement benefits are paid directly when incurred; accordingly, these payments are not reflected as changes in plan assets in the following table.

The status of the company’s pension plans and other postretirement benefit plans for 2001 and 2000 is as follows:

FS-36

NOTE 20. EMPLOYEE BENEFIT PLANS — Continued


		Pension Benefits

		2001						2000						Other Benefits

		U.S.			Int'l.			U.S.			Int'l.			2001			2000

CHANGE IN BENEFIT OBLIGATION




	Benefit obligation at January 1	$	4,977		$	1,736		$	5,070		$	1,737		$	2,247		$	2,103




	Service cost		111			47			118			47			21			20




	Interest cost		355			136			363			133			165			161




	Plan participants’ contributions		2			2			2			1			—			18




	Plan amendments		12			13			7			3			(10	)		—




	Actuarial loss		341			108			77			84			244			134




	Foreign currency exchange rate changes		—			(94	)		—			(151	)		(9	)		(7	)




	Benefits paid		(532	)		(110	)		(659	)		(121	)		(158	)		(182	)




	Curtailment		(47	)		—			—			(3	)		(3	)		—




	Special termination benefits¹		47			14			—			6			29			—




	Plan divestiture		—			(4	)		(1	)		—			—			—




	Acquisitions/joint ventures		(86	)		—			—			—			—			—

	Benefit obligation at December 31		5,180			1,848			4,977			1,736			2,526			2,247

CHANGE IN PLAN ASSETS




Fair value of plan assets at January 1			5,098			1,757			5,685			1,914			—			—




	Actual return on plan assets		(221	)		(90	)		27			71			—			—




	Foreign currency exchange rate changes		—			(56	)		—			(155	)		—			—




	Employer contribution		2			26			21			47			—			—




	Plan participants’ contributions		2			2			2			1			—			—




	Expenses		(6	)		—			(8	)		—			—			—




	Benefits paid		(475	)		(88	)		(623	)		(125	)		—			—




	Plan divestiture		—			(4	)		(2	)		—			—			—




	Curtailment		—			—			(4	)		4			—			—

Fair value of plan assets at December 31			4,400			1,547			5,098			1,757			—			—

FUNDED STATUS			(780	)		(301	)		121			21			(2,526	)		(2,247	)




Unrecognized net actuarial loss (gain)			837			493			(29	)		161			93			(145	)




Unrecognized prior-service cost			129			70			185			75			(24	)		(7	)




Unrecognized net transitional assets			—			(7	)		(2	)		(12	)		—			—

Total recognized at December 31		$	186		$	255		$	275		$	245		$	(2,457	)	$	(2,399	)

AMOUNTS RECOGNIZED IN THE CONSOLIDATED BALANCE SHEET AT DECEMBER 31




	Prepaid benefit cost	$	568		$	574		$	560		$	557		$	—		$	—




	Accrued benefit liability		(529	)		(334	)		(438	)		(330	)		(2,457	)		(2,399	)




	Intangible asset		10			12			10			12			—			—




	Accumulated other comprehensive income²		137			3			143			6			—			—

Net amount recognized		$	186		$	255		$	275		$	245		$	(2,457	)	$	(2,399	)

Weighted-average assumptions as of December 31 Discount rate			7.3	%		7.7	%		7.5	%		7.8	%		7.3	%		7.6	%




	Expected return on plan assets		8.8	%		8.9	%		10.0	%		9.1	%		—			—




	Rate of compensation increase		4.0	%		5.4	%		4.1	%		5.0	%		4.1	%		4.4	%

		1 Primarily relates to a special involuntary termination enhancement to pension and postretirement benefits under the Texaco change-in-control program in 2001.




		2 Accumulated other comprehensive income includes deferred income taxes of $48 and $1 in 2001 for U.S. and International, respectively, and $47 and $2 in 2000 for U.S. and International, respectively.

FS-37

Notes to Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 20. EMPLOYEE BENEFIT PLANS — Continued

The components of net periodic benefit cost for 2001, 2000 and 1999 were:


	Pension Benefits

	2001						2000						1999						Other Benefits

	U.S.			Int'l.			U.S.			Int'l.			U.S.			Int'l.			2001			2000			1999

Service cost	$	111		$	47		$	118		$	47		$	134		$	46		$	21		$	20		$	28




Interest cost		355			136			363			133			350			137			165			161			153




Expected return on plan assets		(443	)		(170	)		(503	)		(167	)		(491	)		(146	)		—			—			—




Amortization of transitional assets		(2	)		(4	)		(31	)		(6	)		(36	)		(17	)		—			—			—




Amortization of prior-service costs		25			12			30			12			27			16			(1	)		(1	)		—




Recognized actuarial losses (gains)		13			7			10			(2	)		3			(2	)		(6	)		(10	)		1




Settlement losses (gains)		12			—			(61	)		1			(103	)		1			—			—			—




Curtailment losses (gains)		26			—			(20	)		2			6			1			20			(15	)		(12	)




Special termination benefit recognition*		47			14			—			6			205			2			29			—			—

Net periodic benefit cost	$	144		$	42		$	(94	)	$	26		$	95		$	38		$	228		$	155		$	170

Primarily relates to a special involuntary termination enhancement to pension and postretirement benefits under the Texaco change-in-control program in 2001 and a special involuntary termination enhancement to pension benefits in 1999 under a Chevron companywide restructuring program.

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for pension plans with accumulated benefit obligations in excess of plan assets were $2,496, $2,187 and $1,269, respectively, at December 31, 2001, and $850, $737 and $33, respectively, at December 31, 2000.

For postretirement benefit measurement purposes, one set of health care cost-trend rates was used for pre-age 65 and post-age 65 retirees. Starting in 2002, with approximately an 11 percent cost increase over the previous year, the trend rates gradually drop to the ultimate rate of 4.5 percent over 5 years. A one-percentage-point change in the assumed health care cost-trend rates would have had the following effects:


	One Percent		One Percent
	Increase		Decrease

Effect on total service and interest cost components	$	20	$	(20	)




Effect on postretirement benefit obligation	$	231	$	(193	)

Profit Sharing/Savings Plan Eligible employees of ChevronTexaco and certain of its subsidiaries participate in either the Chevron Profit Sharing/Savings Plan or the Employees Thrift Plan of Texaco. Charges to expense for these plans were $157, $63 and $64 in 2001, 2000 and 1999, respectively.

Employee Stock Ownership Plans (ESOP) In December 1989, Chevron established a leveraged ESOP as part of the Profit Sharing/Savings Plan. The ESOP provides a partial prefunding of the company’s future commitments to the Profit Sharing/ Savings Plan, which will result in annual income tax savings for the company.

In 1988, Texaco established a leveraged ESOP as part of the Employees Thrift Plan of Texaco Inc. The Thrift Plan ESOP loan was satisfied in December 2000. The ESOP was designed to provide participants with a benefit of approximately 6 percent of base pay.

As permitted by American Institute of Certified Public Accountants (AICPA) Statement of Position 93-6, “Employers’ Accounting for Employee Stock Ownership Plans,” the company has elected to continue its practices, which are based on Statement of Position 76-3, “Accounting Practices for Certain Employee Stock Ownership Plans,” and subsequent consensus of the Emerging Issues Task Force of the Financial Accounting Standards Board. The debt of the ESOPs is recorded as debt, and shares pledged as collateral are reported as “Deferred compensation and benefit plan trust” in the Consolidated Balance Sheet and the Consolidated Statement of Stockholders’ Equity. The company reports compensation expense equal to ESOP debt principal repayments less dividends received by the ESOPs. Interest incurred on the ESOP debt is recorded as interest expense. Dividends paid on ESOP shares are reflected as a reduction of retained earnings. All ESOP shares are considered outstanding for earnings-per-share computations.

Expense recorded for the ESOPs was $75, $26 and $62 in 2001, 2000 and 1999, respectively, including $62, $48 and $51 of interest expense related to ESOP debt. All dividends paid on the ESOP shares held are used to service the ESOP debt. The dividends used were $86, $77 and $63 in 2001, 2000 and 1999, respectively.

The company made ESOP contributions of $75, $1 and $67 in 2001, 2000 and 1999, respectively, to satisfy ESOP debt service in excess of dividends received by the ESOP. The ESOP shares were pledged as collateral for the debt. Shares are released from a suspense account and allocated to the accounts of plan participants, based on the debt service deemed to be paid in the year in proportion to the total of current-year and remaining debt service. The charge (credit) to compensation expense was $13, $(22) and $11 in 2001, 2000 and 1999, respectively. ESOP shares

FS-38

NOTE 20. EMPLOYEE BENEFIT PLANS — Continued

as of December 31, 2001 and 2000, were as follows:


Thousands	2001		2000

Allocated shares		21,790		23,706




Unallocated shares		8,836		10,877

Total ESOP shares		30,626		34,583

Benefit Plan Trust Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2001, the trust contained 7.1 million shares of ChevronTexaco treasury stock. The company intends to continue to pay its obligations under the benefit plans. The trust will use the shares, proceeds from the sale of such shares and dividends on such shares to pay benefits only to the extent that the company does not pay such benefits. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The shares held by the trust are not considered outstanding for earnings-per-share purposes until distributed or sold by the trust in payment of benefit obligations.

Management Incentive Plans Chevron had two incentive plans, the Management Incentive Plan (MIP) and the Long-Term Incentive Plan (LTIP) for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. The plans will be expanded to include former employees of Texaco and Caltex. The MIP is an annual cash incentive plan that links awards to performance results of the prior year. The cash awards may be deferred by conversion to stock units or other investment fund alternatives. Awards under the LTIP may take the form of, but are not limited to, stock options, restricted stock, stock units and nonstock grants. Texaco also had a cash incentive program and a Stock Incentive Plan (SIP) that included stock options, restricted stock and other incentive awards for executives, directors and key employees. Awards under the Caltex LTIP were in the form of performance units and stock appreciation rights. Charges to expense for the combined management incentive plans, excluding expense related to LTIP and SIP stock options and restricted stock awards, which are discussed in Note 21, were $93, $83 and $54 in 2001, 2000 and 1999, respectively.

Other Incentive Plans Chevron had a program that provided eligible employees with an annual cash bonus if the company achieved certain financial and safety goals. The program was expanded to include former employees of Texaco and Caltex post-merger. Texaco and Caltex also had similar programs. Charges for the combined programs were $154, $230 and $60 in 2001, 2000 and 1999, respectively.

NOTE 21. STOCK OPTIONS

The company applies APB Opinion No. 25 and related interpretations in accounting for its stock-based compensation programs, which are described below. Stock-based compensation expense recognized in connection with these programs was $111, $23 and $21 in 2001, 2000 and 1999, respectively.

Had compensation cost for the company’s combined stock options been determined based on the fair market value at the grant dates of the awards consistent with the methodology prescribed by FAS No. 123, net income and earnings per share for 2001, 2000 and 1999 would have been the pro forma amounts shown on the following table:


			2001		2000		1999

Net income As reported			$	3,288	$	7,727	$	3,247




	Pro forma		$	3,202	$	7,687	$	3,134




Earnings per share




	As reported — basic		$	3.10	$	7.23	$	3.01




		— diluted	$	3.09	$	7.21	$	3.00




	Pro forma — basic		$	3.02	$	7.19	$	2.91




		— diluted	$	3.01	$	7.18	$	2.90

The effects of applying FAS No. 123 in this pro forma disclosure are not indicative of future amounts. FAS No. 123 does not apply to awards granted prior to 1995. In addition, certain options vest over several years, and awards in future years, whose terms and conditions may vary, are anticipated.

Broad-Based Employee Stock Options In 1996, Chevron granted to all its eligible employees an option for 150 shares of stock or equivalents at an exercise price of $51.875 per share. In addition, a portion of the awards granted under the LTIP had terms similar to the broad-based employee stock options. The options vested in June 1997.

Options for 7,204,800 shares, including similar-termed LTIP awards, were granted for this program in 1996, and the program expired in 1999.

In 1998, Chevron announced another broad-based Employee Stock Option Program that granted to all eligible employees an option that varied from 100 to 300 shares of stock or equivalents, dependent on the employee’s salary or job grade. These options vested after two years in February 2000. Options for 4,820,800 shares were awarded at an exercise price of $76.3125 per share. Outstanding option shares were 3,064,367 at year-end 2000. In 2001, exercises of 653,096 and forfeitures of 44,960 reduced the outstanding option shares to 2,366,311 at the end of the year. The options expire February 11, 2008. The company recorded expenses of $1, $(2) and $4 for these options in 2001, 2000 and 1999, respectively.

The fair value of each option share for the 1998 program on the date of grant under FAS No. 123 was estimated at $19.08 using the average results of Black-Scholes models for the preceding 10 years. The 10-year averages of each assumption used by the Black-Scholes models were: a risk-free interest rate of 7.0 percent, a dividend yield of 4.2 percent, an expected life of seven years and a volatility of 24.7 percent.

Long-Term Incentive Plan Stock options granted under the LTIP are generally awarded at market price on the date of grant and are exercisable not earlier than one year and not later than 10 years from the date of grant. However, a portion of the LTIP options granted in 1996 had terms similar to the broad-based employee stock options. The maximum number of shares that may be granted each year is 1 percent of the total outstanding shares of common stock as of January 1 of such year.

Under the Texaco Stock Incentive Plan (SIP), the maximum number of shares that were granted as stock options or restricted stock was 1 percent of the common stock outstanding on December 31 of the previous year. Restricted shares granted under SIP

FS-39

Notes to Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 21. STOCK OPTIONS — Continued

contained a performance element, which had to be satisfied in order for all or a specified portion of the shares to vest. Upon the merger, all restricted shares became vested and converted to ChevronTexaco shares at the merger exchange ratio of 0.77. Restricted performance shares awarded in each year under the SIP on a converted basis were as follows:


	2001		2000		1999

Shares (thousands)		392		409		214




Weighted-average fair value	$	91.05	$	73.40	$	81.53

Stock options granted under the SIP extend for 10 years from the date of grant and vest over a two-year period at a rate of 50 percent in the first year and 50 percent in the second year. The exercise price cannot be less than the fair market value of the underlying shares of common stock on the date of the grant. The plan provides for restored options. This feature enables a participant who exercises a stock option by exchanging previously acquired common stock or who has shares withheld to satisfy tax withholding obligations to receive new options equal to the number of shares exchanged or withheld. The restored options are fully exercisable six months after the date of grant and the exercise price is the fair market value of the common stock on the day the restored option is granted. Amounts charged to compensation expense in 2001, 2000 and 1999 were $110, $25 and $19.

The fair market value of each stock option granted is estimated on the date of grant under FAS No. 123 using the Black-Scholes option-pricing model with the following weighted-average assumptions:


		2001			2000			1999

Chevron Plans:




	Expected life in years		7			7			7




	Risk-free interest rate		4.1	%		5.8	%		5.5	%




	Volatility		24.4	%		25.6	%		20.1	%




	Dividend yield		3.0	%		3.0	%		3.0	%




Texaco Plans:




	Expected life in years		2			2			2




	Risk-free interest rate		3.9	%		6.4	%		5.4	%




	Volatility		25.9	%		33.8	%		29.1	%




	Dividend yield		3.1	%		3.0	%		3.0	%

The Black-Scholes weighted-average fair value of the Chevron options granted during 2001, 2000 and 1999 was $20.45, $22.34 and $20.40 per share, respectively, and the weighted-average fair value of the Texaco options granted during 2001, 2000 and 1999 was $12.90, $11.56 and $11.21 per share.

Upon the merger, outstanding Texaco stock options were converted to ChevronTexaco options at the merger exchange rate of 0.77. The following table presents the combined stock options outstanding as of December 31, 2001, 2000 and 1999, with information on Texaco’s stock options on a converted basis. This table excludes Chevron LTIP awards granted with terms similar to the broad-based employee stock options:


	Options			Weighted-Average
	(thousands)			Exercise Price

Outstanding at December 31, 1998		18,167		$	67.94

Granted		3,388			86.05




Exercised		(7,584	)		71.35




Restored		5,735			83.83




Forfeited		(783	)		83.62

Outstanding at December 31, 1999		18,923		$	73.99

Granted		3,763			77.18




Exercised		(1,460	)		53.99




Restored		456			78.42




Forfeited		(812	)		84.18

Outstanding at December 31, 2000		20,870		$	75.67

Granted		3,777			89.84




Exercised		(8,209	)		78.16




Restored		6,766			89.77




Forfeited		(584	)	$	85.76

Outstanding at December 31, 2001		22,620		$	81.13

Exercisable at December 31




1999		12,735		$	68.87




2000		16,021		$	74.95




2001		19,028		$	79.64

The following table summarizes information on stock options outstanding at December 31, 2001:


				Options Outstanding						Options Exercisable

						Weighted-
						Average		Weighted-				Weighted-
Range of				Number		Remaining		Average		Number		Average
Exercise				Outstanding		Contractual		Exercise		Exercisable		Exercise
Prices				(Thousands)		Life (Years)		Price		(Thousands)		Price

	$31 to $41				153		0.5	$	34.43		153	$	34.43




		41 to 51			2,057		2.8		45.48		2,057		45.48




			51 to 61		51		5.2		56.34		51		56.34




			61 to 71		739		4.8		66.28		734		66.27




			71 to 81		4,871		6.4		78.96		4,871		78.96




			81 to 91		10,973		7.0		86.80		7,981		86.34




		91 to 101			3,776		7.4		91.81		3,181		91.62

$31 to $101					22,620		6.4	$	81.13		19,028	$	79.64

NOTE 22. OTHER CONTINGENCIES AND COMMITMENTS

The U.S. federal income tax liabilities have been settled through 1993 for Chevron and Caltex and through 1991 for Texaco. 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 businesses, is not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provision has been made for income and franchise taxes for all open years.

At December 31, 2001, the company and its subsidiaries, as direct or indirect guarantors, had contingent liabilities of $1,118 for notes of affiliated companies and $742 for notes of others. Following the February 2002 disposition of the interests in

FS-40

NOTE 22. OTHER CONTINGENCIES AND COMMITMENTS – Continued

Equilon and Motiva, contingent liabilities for notes of affiliated companies were reduced by $432.

The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, throughput agreements and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The aggregate amounts of required payments under these various commitments are 2002 – $1,370; 2003 – $1,402; 2004 – $1,302; 2005 – $1,179; 2006 – $1,094; 2007 and after – $1,311. Total payments under the agreements were $1,509 in 2001, $1,506 in 2000 and $1,165 in 1999.

The company has commitments related to preferred shares of subsidiary companies, which are accounted for as minority interest. MVP Production Inc., a subsidiary, has variable rate cumulative preferred shares of $75 owned by one minority holder. The shares are voting and are redeemable in 2003. Dividends on these shares were $4 in 2001, 2000 and 1999. Texaco Capital LLC, a wholly owned finance subsidiary, has issued $65 of Deferred Preferred Shares, Series C. Dividends amounting to $59 on Series C, at a rate of 7.17 percent compounded annually, will be paid at the redemption date of February 28, 2005, unless earlier redemption occurs. Early redemption may result upon the occurrence of certain specific events.

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

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

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

The company’s operations, particularly exploration and production, can be affected by other changing economic, regulatory and political environments in the various countries in which it operates, including the United States. In certain locations, host governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries. Internal unrest or strained relations between a host government and the company or other governments may affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results, and are carefully considered by management when evaluating the level of current and future activity in such countries.

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

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

FS-41

Notes to Consolidated Financial Statements

Millions of dollars, except per-share amounts

NOTE 23. EARNINGS PER SHARE (EPS)

Basic EPS includes the effects of deferrals of salary and other compensation awards that are invested in ChevronTexaco stock units by certain officers and employees of the company and is based upon net income less preferred stock dividend requirements. Diluted EPS includes the effects of these deferrals as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (see Note 21, “Stock Options”). The following table sets forth the computation of basic and diluted EPS:


	2001							2000							1999



	Net			Shares		Per-Share		Net			Shares		Per-Share		Net			Shares		Per-Share
	Income			(millions)		Amount		Income			(millions)		Amount		Income			(millions)		Amount

Net income	$	3,288						$	7,727						$	3,247




Weighted-average common shares outstanding					1,059.3							1,066.6							1,067.7




Dividend equivalents paid on Chevron stock units		2							2							3




Deferred awards held as Chevron stock units					0.8							0.9							1.1




Preferred stock dividends		(6	)						(15	)						(29	)

BASIC EPS COMPUTATION	$	3,284			1,060.1	$	3.10	$	7,714			1,067.5	$	7.23	$	3,221			1,068.8	$	3.01




Dilutive effects of stock options, restricted stock and convertible debentures		4			2.8				3			2.4				3			4.8

DILUTED EPS COMPUTATION	$	3,288			1,062.9	$	3.09	$	7,717			1,069.9	$	7.21	$	3,224			1,073.6	$	3.00

FS-42

Quarterly Results and Stock Market Data


Unaudited					2001												2000

Millions of dollars, except per-share amounts					4TH Q			3RD Q			2ND Q			1ST Q			4TH Q			3RD Q			2ND Q		1ST Q

REVENUES AND OTHER INCOME




Sales and other operating revenues¹					$	21,239		$	25,954		$	28,597		$	28,619		$	31,981		$	30,379		$	28,695	$	26,040




(Loss) income from equity affiliates						(38	)		320			574			288			139			427			245		266




Other income						259			217			89			127			238			384			149		187

TOTAL REVENUES AND OTHER INCOME						21,460			26,491			29,260			29,034			32,358			31,190			29,089		26,493

COSTS AND OTHER DEDUCTIONS




Purchased crude oil and products, operating and other expenses						15,632			18,348			19,834			19,408			22,610			21,837			20,197		18,068




Depreciation, depletion and amortization						3,562			1,172			1,168			1,157			1,529			1,292			1,227		1,273




Taxes other than on income¹						3,557			3,702			3,940			3,957			4,311			3,530			4,058		3,928




Merger-related expenses						1,407			83			48			25			–			–			–		–




Minority interests						32			17			34			38			28			29			27		27




Interest and debt expense						171			186			217			259			267			263			284		296

TOTAL COSTS AND OTHER DEDUCTIONS						24,361			23,508			25,241			24,844			28,745			26,951			25,793		23,592

(LOSS) INCOME BEFORE INCOME TAX						(2,901	)		2,983			4,019			4,190			3,613			4,239			3,296		2,901




INCOME TAX (CREDIT) EXPENSE						(526	)		1,219			1,910			1,757			1,574			1,910			1,555		1,283

NET (LOSS) INCOME BEFORE EXTRAORDINARY ITEM					$	(2,375	)	$	1,764		$	2,109		$	2,433		$	2,039		$	2,329		$	1,741	$	1,618




EXTRAORDINARY LOSS, NET OF INCOME TAX						(147	)		(496	)		–			–			–			–			–		–

NET (LOSS) INCOME²					$	(2,522	)	$	1,268		$	2,109		$	2,433		$	2,039		$	2,329		$	1,741	$	1,618

NET (LOSS) INCOME PER SHARE BEFORE




	EXTRAORDINARY ITEM – BASIC				$	(2.24	)	$	1.66		$	1.99		$	2.30		$	1.93		$	2.18		$	1.62	$	1.50




		– DILUTED			$	(2.24	)	$	1.66		$	1.99		$	2.29		$	1.92		$	2.17		$	1.62	$	1.50

NET (LOSS) INCOME PER SHARE – BASIC					$	(2.38	)	$	1.19		$	1.99		$	2.30		$	1.93		$	2.18		$	1.62	$	1.50




				– DILUTED	$	(2.38	)	$	1.19		$	1.99		$	2.29		$	1.92		$	2.17		$	1.62	$	1.50

DIVIDENDS PAID PER SHARE³					$	0.70		$	0.65		$	0.65		$	0.65		$	0.65		$	0.65		$	0.65	$	0.65




COMMON STOCK PRICE RANGE – HIGH					$	93.77		$	93.61		$	98.49		$	93.45		$	88.94		$	92.31		$	94.88	$	94.25




			– LOW		$	82.00		$	78.60		$	84.59		$	78.44		$	78.19		$	76.88		$	82.31	$	69.94

¹ Includes consumer excise taxes:					$	1,634		$	1,359		$	1,771		$	1,782		$	1,769		$	1,585		$	1,679	$	1,568




² Net (charges) credits for special items and merger effects included in net (loss) income:					$	(3,021	)	$	(416	)	$	(64	)	$	(21	)	$	(254	)	$	(81	)	$	40	$	(83	)




³ Chevron dividend pre-merger

In accordance with pooling-of-interests accounting, the quarterly results in the preceding table give retroactive effect to the merger, with all periods presented as if Chevron and Texaco had always been combined.

The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX) and on the Pacific Exchange. As of March 8, 2002, stockholders of record numbered approximately 250,000. Through October 9, 2001, the common stock traded under the name of Chevron Corporation (trading symbol: CHV).

There are no restrictions on the company’s ability to pay dividends.

FS-43

Five-Year Financial Summary


Millions of dollars, except per-share amounts			2001			2000		1999		1998		1997

COMBINED STATEMENT OF INCOME DATA




REVENUES AND OTHER INCOME




Total sales and other operating revenues			$	104,409		$	117,095	$	84,004	$	71,937	$	99,964




Income from equity affiliates and other income				1,836			2,035		1,709		1,321		2,347

TOTAL REVENUES AND OTHER INCOME				106,245			119,130		85,713		73,258		102,311




TOTAL COSTS AND OTHER DEDUCTIONS				97,954			105,081		79,901		70,422		93,118

INCOME BEFORE INCOME TAXES				8,291			14,049		5,812		2,836		9,193




INCOME TAX EXPENSE				4,360			6,322		2,565		919		3,273

INCOME BEFORE EXTRAORDINARY ITEM			$	3,931		$	7,727	$	3,247	$	1,917	$	5,920




EXTRAORDINARY LOSS, NET OF INCOME TAX				(643	)		–		–		–		–

NET INCOME			$	3,288		$	7,727	$	3,247	$	1,917	$	5,920

NET INCOME PER SHARE BEFORE EXTRAORDINARY ITEM – BASIC			$	3.71		$	7.23	$	3.01	$	1.76	$	5.54




		– DILUTED	$	3.70		$	7.21	$	3.00	$	1.75	$	5.48

NET INCOME PER SHARE – BASIC			$	3.10		$	7.23	$	3.01	$	1.76	$	5.54




	– DILUTED		$	3.09		$	7.21	$	3.00	$	1.75	$	5.48

CASH DIVIDENDS PER SHARE*			$	2.65		$	2.60	$	2.48	$	2.44	$	2.28





COMBINED BALANCE SHEET DATA (AT DECEMBER 31)




Current assets			$	18,327		$	17,913	$	17,043	$	14,157	$	16,161




Noncurrent assets				59,245			59,708		58,337		55,967		53,699

Total assets				77,572			77,621		75,380		70,124		69,860

Short-term debt				8,429			3,094		6,063		5,579		4,076




Other current liabilities				12,225			13,567		11,620		9,480		11,520




Long-term debt and capital lease obligations				8,989			12,821		13,145		11,675		10,708




Other noncurrent liabilities				13,971			14,770		14,761		14,523		13,318

Total liabilities				43,614			44,252		45,589		41,257		39,622

Stockholders’ equity			$	33,958		$	33,369	$	29,791	$	28,867	$	30,238

Chevron dividend pre-merger.

Supplemental Information on Oil and Gas Producing Activities

Unaudited

In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (FAS 69), this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables V through VII present information on the company’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. The Africa geographic area includes activities principally in Nigeria, Angola, Chad, Congo and Democratic Republic of Congo. The Asia-Pacific geographic area includes activities principally in Australia, China, Indonesia, Kazakhstan, Kuwait, Papua New Guinea, Philippines and Thailand. The “Other” geographic category includes activities in the United Kingdom, Canada, Denmark, Netherlands, Norway, Trinidad, Colombia, Venezuela, Brazil, Argentina and other countries. Amounts shown for affiliated companies are ChevronTexaco’s 50 percent equity share of Tengizchevroil (TCO), an exploration and production partnership operating in the Republic of Kazakhstan, and a 30 percent equity share of Hamaca, an exploration and production partnership operating in Venezuela, beginning in 2000. The company increased its ownership in TCO from 45 percent to 50 percent in January 2001.

FS-44

TABLE I – COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS AND DEVELOPMENT¹


		Consolidated Companies										Affiliated Companies

Millions of dollars		U.S.		Africa		Asia-Pacific		Other		Total		TCO²		Hamaca		Worldwide

YEAR ENDED DECEMBER 31, 2001




Exploration




	Wells	$	620	$	172	$	186	$	197	$	1,175	$	–	$	–	$	1,175




	Geological and geophysical		46		35		42		65		188		–		–		188




	Rentals and other		65		48		15		98		226		–		–		226

	Total exploration		731		255		243		360		1,589		–		–		1,589

Property acquisitions³




	Proved⁴		25		4		–		–		29		362		–		391




	Unproved		50		38		12		–		100		108		–		208

	Total property acquisitions		75		42		12		–		129		470		–		599

Development			1,754		551		1,168		494		3,967		266		275		4,508

TOTAL COSTS INCURRED		$	2,560	$	848	$	1,423	$	854	$	5,685	$	736	$	275	$	6,696

YEAR ENDED DECEMBER 31, 2000




Exploration




	Wells	$	526	$	139	$	179	$	63	$	907	$	–	$	–	$	907




	Geological and geophysical		60		35		67		105		267		–		–		267




	Rentals and other		73		43		55		83		254		–		–		254

	Total exploration		659		217		301		251		1,428		–		–		1,428

Property acquisitions³




	Proved⁴		162		1		278		1		442		–		–		442




	Unproved		66		9		–		184		259		–		–		259

	Total property acquisitions		228		10		278		185		701		–		–		701

Development			1,453		435		1,067		718		3,673		240		–		3,913

TOTAL COSTS INCURRED		$	2,340	$	662	$	1,646	$	1,154	$	5,802	$	240	$	–	$	6,042

YEAR ENDED DECEMBER 31, 1999




Exploration




	Wells	$	361	$	115	$	132	$	94	$	702	$	–	$	–	$	702




	Geological and geophysical		87		48		65		94		294		–		–		294




	Rentals and other		81		40		70		57		248		–		–		248

	Total exploration		529		203		267		245		1,244		–		–		1,244

Property acquisitions^3,5




	Proved⁴		13		–		687		864		1,564		–		–		1,564




	Unproved		66		38		750		477		1,331		–		–		1,331

	Total property acquisitions		79		38		1,437		1,341		2,895		–		–		2,895

Development			1,230		540		829		606		3,205		148		–		3,353

TOTAL COSTS INCURRED		$	1,838	$	781	$	2,533	$	2,192	$	7,344	$	148	$	–	$	7,492

¹		Includes costs incurred whether capitalized or expensed. Excludes support equipment expenditures.




²		Includes acquisition costs for an additional 5 percent interest in 2001.




³		Proved amounts include wells, equipment and facilities associated with proved reserves.




⁴		Does not include properties acquired through property exchanges.




⁵		Includes acquisition costs and related deferred income taxes for purchases of Rutherford-Moran Oil Corporation and Petrolera Argentina San Jorge S.A.

FS-45

Supplemental Information on Oil and Gas Producing Activities – Continued

Unaudited

TABLE II – CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES


	Consolidated Companies										Affiliated Companies

Millions of dollars	U.S.		Africa		Asia-Pacific		Other		Total		TCO		Hamaca*		Worldwide

AT DECEMBER 31, 2001




Unproved properties	$	753	$	304	$	565	$	1,168	$	2,790	$	108	$	–	$	2,898




Proved properties and related producing assets		35,665		5,487		10,332		9,435		60,919		1,878		88		62,885




Support equipment		766		390		2,177		313		3,646		293		–		3,939




Deferred exploratory wells		91		450		128		114		783		–		–		783




Other uncompleted projects		1,080		690		654		437		2,861		245		376		3,482

GROSS CAPITALIZED COSTS		38,355		7,321		13,856		11,467		70,999		2,524		464		73,987

Unproved properties valuation		382		86		73		222		763		–		–		763




Proved producing properties – Depreciation and depletion		25,844		2,998		4,733		4,827		38,402		219		3		38,624




Future abandonment and restoration		1,016		449		281		342		2,088		19		–		2,107




Support equipment depreciation		452		160		1,122		162		1,896		123		–		2,019

Accumulated provisions		27,694		3,693		6,209		5,553		43,149		361		3		43,513

NET CAPITALIZED COSTS	$	10,661	$	3,628	$	7,647	$	5,914	$	27,850	$	2,163	$	461	$	30,474

AT DECEMBER 31, 2000




Unproved properties	$	1,233	$	176	$	540	$	1,219	$	3,168	$	378	$	63	$	3,609




Proved properties and related producing assets		34,587		5,050		8,905		8,702		57,244		1,158		71		58,473




Support equipment		721		366		2,126		272		3,485		254		42		3,781




Deferred exploratory wells		182		407		120		161		870		–		–		870




Other uncompleted projects		741		640		674		570		2,625		136		–		2,761

GROSS CAPITALIZED COSTS		37,464		6,639		12,365		10,924		67,392		1,926		176		69,494

Unproved properties valuation		317		69		66		170		622		–		–		622




Proved producing properties – Depreciation and depletion		23,528		2,700		3,986		3,940		34,154		131		–		34,285




Future abandonment and restoration		1,071		413		274		317		2,075		13		–		2,088




Support equipment depreciation		380		141		1,224		172		1,917		97		1		2,015

Accumulated provisions		25,296		3,323		5,550		4,599		38,768		241		1		39,010

NET CAPITALIZED COSTS	$	12,168	$	3,316	$	6,815	$	6,325	$	28,624	$	1,685	$	175	$	30,484

AT DECEMBER 31, 1999




Unproved properties	$	1,190	$	185	$	617	$	1,204	$	3,196	$	378	$	–	$	3,574




Proved properties and related producing assets		36,614		4,442		6,745		10,657		58,458		689		–		59,147




Support equipment		913		322		2,151		244		3,630		243		–		3,873




Deferred exploratory wells		196		304		169		141		810		–		–		810




Other uncompleted projects		822		758		969		633		3,182		405		–		3,587

GROSS CAPITALIZED COSTS		39,735		6,011		10,651		12,879		69,276		1,715		–		70,991

Unproved properties valuation		282		54		82		109		527		–		–		527




Proved producing properties – Depreciation and depletion		25,301		2,317		3,376		5,770		36,764		99		–		36,863




Future abandonment and restoration		1,189		383		252		535		2,359		10		–		2,369




Support equipment depreciation		321		114		1,083		76		1,594		80		–		1,674

Accumulated provisions		27,093		2,868		4,793		6,490		41,244		189		–		41,433

NET CAPITALIZED COSTS	$	12,642	$	3,143	$	5,858	$	6,389	$	28,032	$	1,526	$	–	$	29,558

Existing costs were transferred from a consolidated subsidiary to an affiliate at year-end 2000. Previously reported in Consolidated Companies – Other.

FS-46

TABLE III – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES¹

The company’s results of operations from oil and gas producing activities for the years 2001, 2000 and 1999 are shown in the following table. Net income from exploration and production activities as reported on page FS-5 reflects income taxes computed on an effective rate basis. In accordance with FAS No. 69, income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the net income amounts on page FS-5.


			Consolidated Companies															Affiliated Companies

									Asia-
Millions of dollars			U.S.			Africa			Pacific			Other			Total			TCO			Hamaca			Worldwide

YEAR ENDED DECEMBER 31, 2001




Revenues from net production




	Sales		$	5,024		$	1,147		$	1,264		$	2,181		$	9,616		$	673		$	6		$	10,295




	Transfers			3,991			1,913			2,796			1,107			9,807			–			–			9,807

		Total		9,015			3,060			4,060			3,288			19,423			673			6			20,102




Production expenses				(2,272	)		(447	)		(856	)		(687	)		(4,262	)		(142	)		(6	)		(4,410	)




Proved producing properties: depreciation, depletion and abandonment provision				(1,614	)		(344	)		(498	)		(658	)		(3,114	)		(80	)	$	(1	)		(3,195	)




Exploration expenses				(424	)		(132	)		(234	)		(298	)		(1,088	)		–			–			(1,088	)




Unproved properties valuation				(38	)		(33	)		(9	)		(77	)		(157	)		–			–			(157	)




Other (expense) income²				(1,823	)		(110	)		(209	)		(5	)		(2,147	)		9			2			(2,136	)

	Results before income taxes			2,844			1,994			2,254			1,563			8,655			460			1			9,116




Income tax expense				(1,074	)		(1,455	)		(1,432	)		(620	)		(4,581	)		(138	)		–			(4,719	)

RESULTS OF PRODUCING OPERATIONS			$	1,770		$	539		$	822		$	943		$	4,074		$	322		$	1		$	4,397

YEAR ENDED DECEMBER 31, 2000




Revenues from net production




	Sales		$	5,878		$	2,804		$	1,404		$	2,310		$	12,396		$	710		$	–		$	13,106




	Transfers			4,387			650			3,203			1,409			9,649			–			–			9,649

	Total			10,265			3,454			4,607			3,719			22,045			710			–			22,755




Production expenses				(2,182	)		(405	)		(865	)		(727	)		(4,179	)		(114	)		–			(4,293	)




Proved producing properties: depreciation, depletion and abandonment provision				(1,558	)		(337	)		(585	)		(676	)		(3,156	)		(53	)		–			(3,209	)




Exploration expenses				(395	)		(166	)		(176	)		(217	)		(954	)		–			–			(954	)




Unproved properties valuation				(49	)		(16	)		(7	)		(75	)		(147	)		–			–			(147	)




Other (expense) income²				(631	)		45			(13	)		237			(362	)		(56	)		–			(418	)

	Results before income taxes			5,450			2,575			2,961			2,261			13,247			487			–			13,734




Income tax expense				(1,927	)		(1,974	)		(1,724	)		(984	)		(6,609	)		(146	)		–			(6,755	)

RESULTS OF PRODUCING OPERATIONS			$	3,523		$	601		$	1,237		$	1,277		$	6,638		$	341		$	–		$	6,979

YEAR ENDED DECEMBER 31, 1999




Revenues from net production




	Sales		$	3,411		$	1,756		$	861		$	1,548		$	7,576		$	356		$	–		$	7,932




	Transfers			2,830			446			2,108			948			6,332			–			–			6,332

	Total			6,241			2,202			2,969			2,496			13,908			356			–			14,264




Production expenses				(1,948	)		(394	)		(747	)		(747	)		(3,836	)		(88	)		–			(3,924	)




Proved producing properties: depreciation, depletion and abandonment provision				(1,527	)		(338	)		(469	)		(624	)		(2,958	)		(47	)		–			(3,005	)




Exploration expenses				(410	)		(164	)		(286	)		(227	)		(1,087	)		–			–			(1,087	)




Unproved properties valuation				(53	)		(8	)		(26	)		(30	)		(117	)		–			–			(117	)




Other (expense) income²				(585	)		(61	)		(69	)		5			(710	)		(9	)		–			(719	)

	Results before income taxes			1,718			1,237			1,372			873			5,200			212			–			5,412




Income tax expense				(539	)		(848	)		(852	)		(452	)		(2,691	)		(63	)		–			(2,754	)

RESULTS OF PRODUCING OPERATIONS			$	1,179		$	389		$	520		$	421		$	2,509		$	149		$	–		$	2,658

¹		The value of owned production consumed as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.




²		Includes gas processing fees, net sulfur income, foreign currency transaction gains and losses, certain significant impairment write-downs, miscellaneous expenses, etc. Also includes net income from related oil and gas activities that do not have oil and gas reserves attributed to them (for example, net income from technical and operating service agreements) and items identified in the Management’s Discussion and Analysis on pages FS-5 and FS-6.

FS-47

Supplemental Information on Oil and Gas Producing Activities – Continued

Unaudited

TABLE IV – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES – UNIT PRICES AND COSTS^1,2


		Consolidated Companies										Affiliated Companies

		U.S.		Africa		Asia-Pacific		Other		Total		TCO		Hamaca		Worldwide

YEAR ENDED DECEMBER 31, 2001




	Average sales prices




	Liquids, per barrel	$	21.34	$	23.70	$	20.11	$	22.59	$	21.68	$	13.31	$	12.45	$	21.08




	Natural gas, per thousand cubic feet		4.38		0.04		3.04		2.51		3.78		0.47		–		3.69




Average production costs, per barrel			5.90		3.39		4.20		4.17		4.81		2.54		13.09		4.68

YEAR ENDED DECEMBER 31, 2000




	Average sales prices




	Liquids per barrel	$	25.61	$	26.58	$	22.97	$	27.34	$	25.35	$	20.14	$	–	$	25.09




	Natural gas, per thousand cubic feet		3.87		0.03		2.57		2.29		3.39		0.13		–		3.33




Average production costs, per barrel			5.23		3.04		4.17		4.49		4.55		2.91		–		4.48

YEAR ENDED DECEMBER 31, 1999




	Average sales prices




	Liquids, per barrel	$	14.92	$	17.39	$	14.67	$	16.94	$	15.63	$	10.53	$	–	$	15.40




	Natural gas, per thousand cubic feet		2.12		0.05		1.86		1.83		2.02		0.38		–		2.00




Average production costs, per barrel			4.37		3.06		3.61		4.48		4.04		2.39		–		3.98

¹		The value of owned production consumed as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.




²		Natural gas converted to crude oil-equivalent gas (OEG) barrels at a rate of 6 MCF=1 OEG barrel.

TABLE V – RESERVE QUANTITY INFORMATION

The company’s estimated net proved underground oil and gas reserves and changes thereto for the years 2001, 2000 and 1999 are shown in the following table. Proved reserves are estimated by company asset teams composed of earth scientists and reservoir engineers. These proved reserve estimates are reviewed annually by the company’s Reserves Advisory Committee to ensure that rigorous professional standards and the reserves definitions prescribed by the U.S. Securities and Exchange Commission are consistently applied throughout the company.

Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change as additional information becomes available.

Proved reserves do not include additional quantities recoverable beyond the term of the lease or concession agreement or that may result from extensions of currently proved areas or from applying secondary or tertiary recovery processes not yet tested and determined to be economic.

Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.

“Net” reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.

FS-48

TABLE V – RESERVE QUANTITY INFORMATION – Continued

ChevronTexaco operates, under a risked service agreement, Venezuela’s Block LL-652, located in the northeast section of Lake Maracaibo. ChevronTexaco is accounting for LL-652 as an oil and gas activity and, at December 31, 2001, had recorded 18 million barrels of proved crude oil reserves.

No reserve quantities have been recorded for the company’s other service agreements – the Boscan Field in Venezuela and a long-term purchase agreement associated with a service agreement for the Chuchupa Field in Colombia for the period 2005 – 2016.


NET PROVED RESERVES OF CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS
		Million of barrels

		Consolidated Companies															Affiliates

								Asia-															World-
		U.S.			Africa			Pacific			Other			Total			TCO			Hamaca			wide

RESERVES AT JANUARY 1, 1999			2,972			1,359			2,082			782			7,195			1,075			–			8,270




Changes attributable to:




	Revisions		(12	)		4			(178	)		31			(155	)		115			–			(40	)




	Improved recovery		78			62			112			21			273			–			–			273




	Extensions and discoveries		116			47			27			49			239			76			–			315




	Purchases¹		35			–			59			177			271			–			–			271




	Sales²		(76	)		–			–			(2	)		(78	)		–			–			(78	)




	Production		(259	)		(128	)		(215	)		(112	)		(714	)		(33	)		–			(747	)

RESERVES AT DECEMBER 31, 1999			2,854			1,344			1,887			946			7,031			1,233			–			8,264




Changes attributable to:




	Revisions		(26	)		48			109			14			145			105			–			250




	Improved recovery		83			20			69			9			181			–			–			181




	Extensions and discoveries		85			92			40			57			274			7			374			655




	Purchases¹		8			131			–			3			142			–			–			142




	Sales²		(146	)		–			–			(96	)		(242	)		–			–			(242	)




	Production		(244	)		(130	)		(211	)		(111	)		(696	)		(35	)		–			(731	)

RESERVES AT DECEMBER 31, 2000			2,614			1,505			1,894			822			6,835			1,310			374			8,519




Changes attributable to:




	Revisions		(225	)		45			135			(60	)		(105	)		46			(2	)		(61	)




	Improved recovery		79			35			47			51			212			–			–			212




	Extensions and discoveries		67			88			34			40			229			88			115			432




	Purchases¹		1			–			–			–			1			146			–			147




	Sales²		(11	)		–			–			–			(11	)		–			–			(11	)




	Production		(224	)		(129	)		(204	)		(108	)		(665	)		(49	)		–			(714	)

RESERVES AT DECEMBER 31, 2001			2,301			1,544			1,906			745			6,496			1,541			487			8,524

Developed reserves

	At January 1, 1999		2,397			941			1,477			482			5,297			646			–			5,943




	At December 31, 1999		2,266			980			1,314			636			5,196			790			–			5,986




	At December 31, 2000		2,083			976			1,276			538			4,873			795			–			5,668




	At December 31, 2001		1,887			923			1,491			517			4,818			1,007			38			5,863

[Additional columns below]

[Continued from above table, first column(s) repeated]


NET PROVED RESERVES OF NATURAL GAS
		Billions of cubic feet

		Consolidated Companies															Affiliates

								Asia-														World-
		U.S.			Africa			Pacific			Other			Total			TCO			Hamaca		wide

RESERVES AT JANUARY 1, 1999			8,602			292			2,660			2,882			14,436			1,384			–		15,820




Changes attributable to:




	Revisions		(141	)		49			411			251			570			126			–		696




	Improved recovery		11			–			237			10			258			–			–		258




	Extensions and discoveries		789			–			51			186			1,026			98			–		1,124




	Purchases¹		35			–			901			183			1,119			–			–		1,119




	Sales²		(155	)		–			–			–			(155	)		–			–		(155	)




	Production		(1,148	)		(15	)		(172	)		(337	)		(1,672	)		(27	)		–		(1,699	)

RESERVES AT DECEMBER 31, 1999			7,993			326			4,088			3,175			15,582			1,581			–		17,163




Changes attributable to:




	Revisions		92			450			308			67			917			126			–		1,043




	Improved recovery		17			–			–			5			22			–			–		22




	Extensions and discoveries		990			1			236			143			1,370			9			33		1,412




	Purchases¹		262			12			–			–			274			–			–		274




	Sales²		(367	)		–			–			(70	)		(437	)		–			–		(437	)




	Production		(1,064	)		(17	)		(190	)		(329	)		(1,600	)		(33	)		–		(1,633	)

RESERVES AT DECEMBER 31, 2000			7,923			772			4,442			2,991			16,128			1,683			33		17,844




Changes attributable to:




	Revisions		(20	)		780			330			(10	)		1,080			317			–		1,397




	Improved recovery		24			7			11			16			58			–			–		58




	Extensions and discoveries		587			329			164			445			1,525			130			9		1,664




	Purchases¹		41			–			6			6			53			187			–		240




	Sales²		(180	)		–			–			–			(180	)		–			–		(180	)




	Production		(988	)		(16	)		(194	)		(360	)		(1,558	)		(55	)		–		(1,613	)

RESERVES AT DECEMBER 31, 2001			7,387			1,872			4,759			3,088			17,106			2,262			42		19,410

Developed reserves

	At January 1, 1999		7,262			266			1,894			2,125			11,547			832			–		12,379




	At December 31, 1999		6,733			276			2,342			2,368			11,719			1,011			–		12,730




	At December 31, 2000		6,408			294			3,108			2,347			12,157			1,019			–		13,176




	At December 31, 2001		6,246			444			3,170			2,231			12,091			1,477			6		13,574

¹		Includes reserves acquired through property exchanges.




²		Includes reserves disposed of through property exchanges.

INFORMATION ON CANADIAN OIL SANDS NET PROVED RESERVES NOT INCLUDED ABOVE:

In addition to conventional liquids and natural gas proved reserves, ChevronTexaco has significant interests in proved oil sands reserves in Canada associated with the Athabasca project. For internal management purposes, ChevronTexaco views these reserves and their development as an integral part of total upstream operations. However, U.S. Securities and Exchange Commission regulations define these reserves as mining-related and not a part of conventional oil and gas reserves. Net proved oil sands reserves were 186 million barrels as of December 31, 2001. Production is expected to begin in late 2002.

The oil sands reserves are not considered in the standardized measure of discounted cash flows for conventional oil and gas reserves, which is found on page FS-50.

FS-49

Supplemental Information on Oil and Gas Producing Activities – Continued

Unaudited

TABLE VI – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES

The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FAS No. 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10 percent midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced.

The information provided does not represent management’s estimate of the company’s expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under FAS No. 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the company’s future cash flows or value of its oil and gas reserves.


	Consolidated Companies															Affiliated Companies

							Asia-
Millions of dollars	U.S.			Africa			Pacific			Other			Total			TCO			Hamaca			Worldwide

AT DECEMBER 31, 2001




Future cash inflows from production	$	54,238		$	28,019		$	43,389		$	20,432		$	146,078		$	29,433		$	5,922			$	181,433




Future production and development costs		(30,871	)		(10,106	)		(20,845	)		(8,873	)		(70,695	)		(8,865	)		(1,093	)			(80,653	)




Future income taxes		(7,981	)		(10,476	)		(9,858	)		(4,370	)		(32,685	)		(5,805	)		(1,642	)			(40,132	)

Undiscounted future net cash flows		15,386			7,437			12,686			7,189			42,698			14,763			3,187				60,648




10 percent midyear annual discount for timing of estimated cash flows		(6,882	)		(3,609	)		(5,857	)		(2,602	)		(18,950	)		(9,121	)		(2,433	)			(30,504	)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS	$	8,504		$	3,828		$	6,829		$	4,587		$	23,748		$	5,642		$	754			$	30,144

AT DECEMBER 31, 2000




Future cash inflows from production	$	127,945		$	34,856		$	47,351		$	27,426		$	237,578		$	30,350		$	3,917			$	271,845




Future production and development costs		(30,305	)		(8,023	)		(18,416	)		(7,466	)		(64,210	)		(7,250	)		(679	)			(72,139	)




Future income taxes		(33,614	)		(16,124	)		(13,245	)		(7,481	)		(70,464	)		(6,440	)		(1,101	)			(78,005	)

Undiscounted future net cash flows		64,026			10,709			15,690			12,479			102,904			16,660			2,137				121,701




10 percent midyear annual discount for timing of estimated cash flows		(27,747	)		(4,186	)		(6,764	)		(4,405	)		(43,102	)		(11,180	)		(1,431	)			(55,713	)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS	$	36,279		$	6,523		$	8,926		$	8,074		$	59,802		$	5,480		$	706			$	65,988

AT DECEMBER 31, 1999




Future cash inflows from production	$	76,931		$	33,218		$	45,358		$	27,973		$	183,480		$	24,380		$	–			$	207,860




Future production and development costs		(26,159	)		(6,430	)		(17,136	)		(8,802	)		(58,527	)		(4,900	)		–				(63,427	)




Future income taxes		(15,354	)		(17,178	)		(13,553	)		(6,970	)		(53,055	)		(4,980	)		–				(58,035	)

Undiscounted future net cash flows		35,418			9,610			14,669			12,201			71,898			14,500			–				86,398




10 percent midyear annual discount for timing of estimated cash flows		(16,296	)		(2,996	)		(6,249	)		(4,607	)		(30,148	)		(10,400	)		–				(40,548	)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS	$	19,122		$	6,614		$	8,420		$	7,594		$	41,750		$	4,100		$	–			$	45,850

FS-50

TABLE VII – CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES


	Consolidated Companies									Affiliated Companies									Worldwide

Millions of dollars	2001			2000			1999			2001			2000			1999			2001			2000			1999

PRESENT VALUE AT JANUARY 1	$	59,802		$	41,750		$	14,447		$	6,186		$	4,100		$	310		$	65,988		$	45,850		$	14,757

Sales and transfers of oil and gas produced, net of production costs		(15,161	)		(17,866	)		(10,072	)		(531	)		(596	)		(268	)		(15,692	)		(18,462	)		(10,340	)




Development costs incurred		3,967			3,673			3,205			541			240			148			4,508			3,913			3,353




Purchases of reserves		40			2,055			3,706			778			–			–			818			2,055			3,706




Sales of reserves		(366	)		(5,010	)		(696	)		–			–			–			(366	)		(5,010	)		(696	)




Extensions, discoveries and improved recovery, less related costs		2,747			8,710			4,866			484			1,112			226			3,231			9,822			5,092




Revisions of previous quantity estimates		524			(428	)		(856	)		400			1,284			738			924			856			(118	)




Net changes in prices, development and production costs		(59,995	)		29,358			49,264			(2,457	)		457			4,650			(62,452	)		29,815			53,914




Accretion of discount		10,144			7,027			2,131			876			582			50			11,020			7,609			2,181




Net change in income tax		22,046			(9,467	)		(24,246	)		119			(993	)		(1,753	)		22,165			(10,460	)		(25,999	)

Net change for the year		(36,054	)		18,052			27,302			210			2,086			3,791			(35,844	)		20,138			31,093

VALUE AT DECEMBER 31	$	23,748		$	59,802		$	41,749		$	6,396		$	6,186		$	4,101		$	30,144		$	65,988		$	45,850

The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs. Changes in the timing of production are included with “Revisions of previous quantity estimates.”

FS-51

EXHIBIT INDEX


Exhibit No.		Description

	3.1*	Restated Certificate of Incorporation of ChevronTexaco Corporation, dated October 9, 2001.

	3.2	By-Laws of ChevronTexaco Corporation, as amended April 25, 2001, filed as Exhibit 3 to ChevronTexaco Corporation’s Report on Form 10-Q for the quarterly period ended March 31, 2001, and incorporated herein by reference.

	4.1	Rights Agreement dated as of November 23, 1998, between ChevronTexaco Corporation and ChaseMellon Shareholder Services L.L.C., as Rights Agent, filed as Exhibit 4.1 to ChevronTexaco Corporation’s Current Report on Form 8-K dated November 23, 1998, and incorporated herein by reference.

	4.2	Amendment No. 1 to Rights Agreement dated as of October 15, 2000, between ChevronTexaco Corporation and ChaseMellon Shareholder Services L.L.C., as Rights Agent, filed as Exhibit 4.2 to ChevronTexaco Corporation’s Registration Statement on Form 8-A dated December 7, 2000, and incorporated herein by reference.
		Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the corporation 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 corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Commission upon request.

	10.1	ChevronTexaco Corporation Deferred Compensation Plan for Directors, as amended and restated effective January 1, 2001, filed as Exhibit 10.1 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.

	10.2	Management Incentive Plan of ChevronTexaco Corporation, as amended and restated effective October 30, 1996, filed as Appendix B to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated March 21, 1997, and incorporated herein by reference.

	10.3	ChevronTexaco Corporation Excess Benefit Plan, amended and restated as of July 1, 1996, filed as Exhibit 10 to ChevronTexaco Corporation’s Report on Form 10-Q for the quarterly period ended March 31, 1997, and incorporated herein by reference.

	10.4	ChevronTexaco Restricted Stock Plan for Non-Employee Directors, as amended and restated effective April 30, 1997, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated March 21, 1997, and incorporated herein by reference.

	10.5	ChevronTexaco Corporation Long-Term Incentive Plan, as amended and restated effective October 30, 1996, filed as Appendix C to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated March 21, 1997, and incorporated herein by reference.

	10.6	ChevronTexaco Corporation Salary Deferral Plan for Management Employees, effective January 1, 1997, filed as Exhibit 10 to ChevronTexaco Corporation’s Report on Form 10-Q for the quarterly period ended June 30, 1997, and incorporated herein by reference.

	10.7	Agreement and Plan of Merger dated as of October 15, 2000, among Texaco Inc., ChevronTexaco Corporation and Keepep Inc., filed as Exhibit 2.1 to a Current Report on Form 8-K filed by the company on October 16, 2000 and an amended Current Report on Form 8-K filed by the company on October 16, 2000, and incorporated herein by reference.

E-1

EXHIBIT INDEX

(continued)


Exhibit No.		Description

	10.8	Amendment No. 1 to Agreement and Plan of Merger, dated as of March 30, 2001, among Texaco Inc., ChevronTexaco Corporation and Keepep Inc., filed as Annex A-1 to Amendment No. 4 to the Registration Statement on Form S-4 filed by ChevronTexaco Corporation on August 27, 2001, and incorporated herein by reference.

	10.10	Stock Option Agreement dated as of October 15, 2000 between ChevronTexaco Corporation and Texaco Inc., filed as Exhibit 2.2 to a Current Report on Form 8-K filed by the company on October 16, 2000, and an amended Current Report on Form 8-K filed by the company on October 16, 2000, and incorporated herein by reference.

	10.11	Stock Option Agreement dated as of October 15, 2000 between ChevronTexaco Corporation and Texaco Inc., filed as Exhibit 2.3 to a Current Report on Form 8-K filed by the company on October 16, 2000, and an amended Current Report on Form 8-K filed by the company on October 16, 2000, and incorporated herein by reference.

	10.12*	Employment Agreement dated as of December 4, 2001 between ChevronTexaco Corporation and Glenn Tilton.

	10.13*	Texaco Inc. Stock Incentive Plan, adopted May 9, 1989, as amended May 13, 1993, and May 13, 1997.

	10.14*	Supplemental Pension Plan of Texaco Inc., dated June 26, 1975.

	10.15*	Supplemental Bonus Retirement Plan of Texaco Inc., dated May 1, 1981.

	10.16*	Texaco Inc. Director and Employee Deferral Plan approved March 28, 1997.

	12.1*	Computation of Ratio of Earnings to Fixed Charges (page E-3).

	21.1*	Subsidiaries of ChevronTexaco Corporation (page E-4).

	23.1*	Consent of PricewaterhouseCoopers LLP (page E-5).

	23.2*	Consent of Arthur Andersen LLP (page E-6).

	24.1 to 24.17	Powers of Attorney for directors and certain officers of ChevronTexaco Corporation, authorizing the signing of the Annual Report on Form 10-K on their behalf.

	99.1*	Definitions of Selected Financial Terms (page E-7).

	99.2	Decision and Order of the Federal Trade Commission filed as Exhibit 99.2 to ChevronTexaco Corporation’s Current Report on Form 8-K filed September 10, 2001, and incorporated herein by reference.

	99.3*	Letter to U.S. Securities and Exchange Commission pursuant to Temporary Note 3T to Article 3 of Regulation S-X. (page E-8)

* Filed herewith.

On October 9, 2001, the company changed its name from Chevron Corporation to ChevronTexaco Corporation. Filings with the Securities and Exchange Commission prior to that date may be found under the company’s former name.

Copies of above exhibits not contained herein are available, at a fee of $2 per document, to any security holder upon written request to the Secretary’s Department, ChevronTexaco Corporation, 575 Market Street, San Francisco, California 94105.

E-2


•	Operational excellence through safe, reliable, efficient and environmentally sound operations;

•	Cost reduction by lowering unit costs through innovation and technology;

•	Capital stewardship by investing in the best project opportunities and executing them successfully (safer, faster, at lower cost); and

•	Profitable growth through leadership in developing new business opportunities in both existing and new markets.


•	Organizational Capability: The company has developed strategies to build capability systems to achieve top performance in the four priorities described above.


¹	Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage is the sum of the company’s fractional interests in gross acreage.

²	Developed acreage is spaced or assignable to productive wells. Undeveloped acreage is acreage where wells have not been drilled or completed to permit commercial production, and may contain undeveloped proved reserves.


¹	Includes wells producing or capable of producing and injection wells temporarily functioning as producing wells. Wells that produce both oil and gas are classified as oil wells.

²	Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company’s fractional interests in gross wells.


¹	mmbbls = millions of barrels

²	bcf = billions of cubic feet

³	Includes equity in affiliates


¹	Indicates the number of wells completed during the year regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of oil or gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency.

²	Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company’s fractional interests in gross wells.


¹	Capacity and input amounts for El Paso represent ChevronTexaco’s share.

²	Refineries in Perth Amboy, New Jersey and Portland, Oregon, which are primarily asphalt plants.

³	Represents ChevronTexaco interests in Equilon and Motiva refineries, which were placed in trust on October 9, 2001, as required by the US Federal Trade Commission, prior to disposition in February 2002.

⁴	ChevronTexaco is negotiating with the Panamanian government in order to cease refining operations and convert these facilities to terminal operations in 2002.

⁵	1999 inputs include Koa Oil Co. Ltd. refineries. Interests sold in 1999.


A.	Texaco Exploration and Production Inc. – Aneth Producing Unit and Gas Plant – Clean Air Act Enforcement Action


C.	Texaco Chemical Company – Clean Water Act Enforcement Action


	(1)	A Current Report on Form 8-K was filed by the company on November 19, 2001. In this report, ChevronTexaco filed the following financial information:


	•	Review of Operations 1998-2000

	•	Audited Supplemental Combined Financial Statements 1998-2000

	•	Supplemental Information on Oil and Gas Producing Activities 1998-2000

	•	Financial Summary 1996-2000

	•	Audited Schedule II – Valuation and Qualifying Accounts


	Other Affiliates							ChevronTexaco Share

YEAR ENDED DECEMBER 31	2001			2000		1999		2001		2000		1999

Total revenues	$	69,549		$	56,602	$	33,772	$	46,649	$	48,925	$	30,135




Income (loss) before income tax expense		646			2,420		1,566		1,430		1,230		925




Net income (loss)		(74	)		1,689		1,326		1,144		1,077		896

AT DECEMBER 31

Current assets	$	17,015		$	18,442	$	7,954	$	5,922	$	8,456	$	4,992




Noncurrent assets		40,191			34,620		18,463		16,276		16,965		12,007




Current liabilities		14,688			16,109		7,665		4,757		7,820		5,615




Noncurrent liabilities		23,255			20,905		10,924		5,600		6,263		3,243

NET EQUITY	$	19,263		$	16,048	$	7,828	$	11,841	$	11,338	$	8,141


		Year ended December 31

		Additions at Cost²						Depreciation Expense

		2001		2000		1999		2001		2000		1999

Exploration and Production




	United States	$	1,973	$	1,931	$	1,383	$	3,508	$	2,138	$	1,932




	International		2,900		3,019		4,934		2,085		1,787		1,546

Total Exploration and Production			4,873		4,950		6,317		5,593		3,925		3,478

Refining, Marketing and Transportation




	United States		626		484		560		476		516		542




	International		566		457		605		555		651		539

Total Refining, Marketing and Transportation			1,192		941		1,165		1,031		1,167		1,081

Chemicals




	United States		10		78		326		22		77		174




	International		31		42		59		19		18		20

Total Chemicals			41		120		385		41		95		194





All Other³			174		202		181		394		134		181

Total United States			2,780		2,695		2,447		4,391		2,825		2,824




Total International			3,500		3,518		5,601		2,668		2,496		2,110

	Total	$	6,280	$	6,213	$	8,048	$	7,059	$	5,321	$	4,934