CHEVRONTEXACO CORP - 10-Q Quarterly Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

		For the quarterly period ended March 31, 2005

or

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

Commission File Number 1-368-2

ChevronTexaco Corporation

(Exact name of registrant as specified in its charter)


Delaware		94-0890210
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification Number)
6001 Bollinger Canyon Road,
San Ramon, California		94583
(Address of principal executive offices)		(Zip Code)

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

NONE

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

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

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

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


Class		Outstanding as of March 31, 2005
Common stock, $.75 par value		2,098,220,174

INDEX


		Page
		No.

	Cautionary Statements Relevant to Forward-Looking Information for the Purpose of “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		2
PART I FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements —
	Consolidated Statement of Income for the Three Months Ended March 31, 2005 and 2004		3
	Consolidated Statement of Comprehensive Income for the Three Months Ended March 31, 2005 and 2004		4
	Consolidated Balance Sheet at March 31, 2005, and December 31, 2004		5
	Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2005 and 2004		6
	Notes to Consolidated Financial Statements		7-23
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24-40
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		41
Item 4.	Controls and Procedures		41
PART II OTHER INFORMATION
Item 1.	Legal Proceedings		42
Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		42
Item 5.	Other Information		43
Item 6.	Exhibits		43
Signature			44
Exhibits: Computation of Ratio of Earnings to Fixed Charges			46
Rule 13a-14(a)/15d-14(a) Certifications			47-48
Section 1350 Certifications			49-50
EXHIBIT 10.13
EXHIBIT 10.14
EXHIBIT 10.15
EXHIBIT 12.1
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE

PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This quarterly report on Form 10-Q of ChevronTexaco Corporation contains forward-looking statements relating to ChevronTexaco’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “projects,” “believes,” “seeks,” “schedules,” “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. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, ChevronTexaco undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Among the factors that could cause actual results to differ materially are crude oil and natural gas prices; refining margins and marketing margins; chemicals prices and competitive conditions affecting supply and demand for aromatics, olefins and additives products; actions of competitors; the competitiveness of alternate energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the ability to successfully consummate the proposed acquisition of Unocal Corporation and successfully integrate the operations of both companies; inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; potential disruption or interruption of the company’s net production or manufacturing facilities due to war, accidents, political events, civil unrest or severe weather; potential liability for remedial actions under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental regulations and litigation (including, particularly, regulations and litigation dealing with gasoline composition and characteristics); potential liability resulting from pending or future litigation; the company’s acquisition or disposition of assets; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” in the company’s Annual Report on Form 10-K. 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.

PART I.

FINANCIAL INFORMATION


Item 1.	*Consolidated Financial Statements*

CHEVRONTEXACO CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF INCOME

(Unaudited)


			Three Months Ended
			March 31,

			2005		2004

			(Millions of dollars, except
			per-share amounts)
Revenues and Other Income
Sales and other operating revenues(1)(2)			$	40,441	$	33,063
Income from equity affiliates				889		444
Other income				277		138

	Total Revenues and Other Income			41,607		33,645

Costs and Other Deductions
Purchased crude oil and products(2)				26,491		20,027
Operating expenses				2,469		2,167
Selling, general and administrative expenses				999		1,021
Exploration expenses				153		85
Depreciation, depletion and amortization				1,334		1,190
Taxes other than on income(1)				5,126		4,765
Interest and debt expense				107		93
Minority interests				21		22

	Total Costs and Other Deductions			36,700		29,370

Income From Continuing Operations Before Income Tax Expense				4,907		4,275
Income Tax Expense				2,230		1,724

Income From Continuing Operations				2,677		2,551
Income From Discontinued Operations				—		11

Net Income			$	2,677	$	2,562

Per Share of Common Stock(3):
	Income From Continuing Operations
		— Basic	$	1.28	$	1.21
		— Diluted	$	1.28	$	1.20
	Income From Discontinued Operations
		— Basic	$	—	$	—
		— Diluted	$	—	$	—
	Net Income
		— Basic	$	1.28	$	1.21
		— Diluted	$	1.28	$	1.20
	Dividends		$	0.40	$	0.36
	Weighted Average Number of Shares Outstanding (000s)
		— Basic		2,090,609		2,126,735
		— Diluted		2,099,899		2,130,735

(1) Includes consumer excise taxes:			$	2,116	$	1,857
(2) Includes amounts in revenues for buy/sell contracts (associated costs are in “Purchased crude oil and products”). See Note 15 starting on page 18:			$	5,290	$	4,256
(3) 2004 restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004

See accompanying notes to consolidated financial statements.

CHEVRONTEXACO CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Unaudited)


			Three Months Ended
			March 31,

			2005			2004

			(Millions of dollars)
Net Income			$	2,677		$	2,562

	Currency translation adjustment			(3	)		1
	Unrealized holding (loss) gain on securities			(33	)		7
	Net derivatives gain on hedge transactions
		Before income taxes		10			4
		Income taxes		(2	)		(2	)

	Total			8			2
	Minimum pension liability adjustment			1			—

Other Comprehensive (Loss) Gain, Net of Tax				(27	)		10

Comprehensive Income			$	2,650		$	2,572

See accompanying notes to consolidated financial statements.

CHEVRONTEXACO CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

At March 31,

At December 31,

2005

2004

(Millions of dollars, except

per-share amounts)

ASSETS

Cash and cash equivalents

10,687

9,291

Marketable securities

1,164

1,451

Accounts and notes receivable, net

13,665

12,429

Inventories:

Crude oil and petroleum products

2,455

2,324

Chemicals

179

173

Materials, supplies and other

462

486

Total inventories

3,096

2,983

Prepaid expenses and other current assets

2,547

2,349

Total Current Assets

31,159

28,503

Long-term receivables, net

1,391

1,419

Investments and advances

14,547

14,389

Properties, plant and equipment, at cost

104,739

103,954

Less: accumulated depreciation, depletion and amortization

60,524

59,496

Properties, plant and equipment, net

44,215

44,458

Deferred charges and other assets

4,196

4,277

Assets held for sale

295

162

Total Assets

95,803

93,208

LIABILITIES AND STOCKHOLDERS’ EQUITY

Short-term debt

624

816

Accounts payable

11,821

10,747

Accrued liabilities

2,805

3,410

Federal and other taxes on income

2,966

2,502

Other taxes payable

1,458

1,320

Total Current Liabilities

19,674

18,795

Long-term debt

10,191

10,217

Capital lease obligations

231

239

Deferred credits and other noncurrent obligations

8,171

7,942

Noncurrent deferred income taxes

7,454

7,268

Reserves for employee benefit plans

3,325

3,345

Minority interests

165

172

Total Liabilities

49,211

47,978

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

—

Common stock (authorized 4,000,000,000 shares, $.75 par value, 2,274,032,014 shares issued at March 31, 2005, and December 31, 2004)

1,706

1,706

Capital in excess of par value

4,199

4,160

Retained earnings

47,258

45,414

Accumulated other comprehensive loss

(346

)

(319

)

Deferred compensation and benefit plan trust

(494

)

(607

)

Treasury stock, at cost (175,811,840 and 166,911,890 shares at March 31, 2005, and December 31, 2004, respectively)

(5,731

)

(5,124

)

Total Stockholders’ Equity

46,592

45,230

Total Liabilities and Stockholders’ Equity

95,803

93,208

See accompanying notes to consolidated financial statements.

CHEVRONTEXACO CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)


				Three Months Ended
				March 31,

				2005			2004

				(Millions of dollars)
Operating Activities
	Net income			$	2,677		$	2,562
	Adjustments
		Depreciation, depletion and amortization			1,334			1,190
		Dry hole expense			60			33
		Distributions less than income from equity affiliates			(210	)		(299	)
		Net before-tax gains on asset retirements and sales			(144	)		(91	)
		Net foreign currency losses			10			12
		Deferred income tax provision			175			242
		Net (increase) decrease in operating working capital			(332	)		209
		Minority interest in net income			21			22
		(Increase) decrease in long-term receivables			(4	)		37
		Decrease in other deferred charges			73			470
		Cash contributions to employee pension plans			(63	)		(549	)
		Other			149			(361	)

			Net Cash Provided by Operating Activities		3,746			3,477

Investing Activities
		Capital expenditures			(1,310	)		(1,354	)
		Proceeds from asset sales			297			381
		Net sales (purchases) of marketable securities			287			(22	)
		Repayment of loans by equity affiliates			37			14

			Net Cash Used for Investing Activities		(689	)		(981	)

Financing Activities
		Net payments of short-term obligations			(72	)		(3	)
		Repayments of long-term debt			(12	)		(141	)
		Cash dividends			(836	)		(775	)
		Dividends paid to minority interests			(26	)		(2	)
		Net (purchases) sales of treasury shares			(568	)		43
		Redemption of preferred stock of subsidiary			(140	)		—

			Net Cash Used For Financing Activities		(1,654	)		(878	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents					(7	)		(26	)

Net Change in Cash and Cash Equivalents					1,396			1,592
Cash and Cash Equivalents at January 1					9,291			4,266

Cash and Cash Equivalents at March 31				$	10,687		$	5,858

See accompanying notes to consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1.	Interim Financial Statements

The accompanying consolidated financial statements of ChevronTexaco Corporation and its subsidiaries (the company) have not been audited by independent accountants. In the opinion of the company’s management, the interim data include all adjustments necessary for a fair statement of the results for the interim periods. These adjustments were of a normal recurring nature, except for the item described in Note 2.

Certain notes and other information have been condensed or omitted from the interim financial statements presented in this Quarterly Report on Form 10-Q. Therefore, these financial statements should be read in conjunction with the company’s 2004 Annual Report on Form 10-K.

The results for the three-month period ended March 31, 2005, are not necessarily indicative of future financial results.


Note 2.	Net Income

Net income for the first quarter 2005 was $2.7 billion, compared with $2.6 billion in the 2004 first quarter. Included in the 2004 results were a special-item charge of $55 million for a litigation matter and income from discontinued operations of $11 million. Information for discontinued operations is discussed in Note 5.

Foreign currency effects reduced earnings by $21 million and $43 million in the 2005 and 2004 periods, respectively.


Note 3.	Agreement to Acquire Unocal

On April 4, 2005, ChevronTexaco announced plans to acquire Unocal Corporation (Unocal) in a stock and cash transaction valued at approximately $16.5 billion for accounting purposes under FAS 141, “Business Combinations.” The acquisition is subject to approvals by certain regulatory agencies and Unocal shareholders. For additional information on this planned acquisition, refer to the company’s Current Report on Form 8-K filed with the U.S. Securities and Exchange Commission on April 7, 2005.


Note 4.	Common Stock Split

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


Note 5.	Assets Held for Sale and Discontinued Operations

At March 31, 2005, and December 31, 2004, the company classified $295 million and $162 million, respectively, of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. Assets in this category at the end of both periods consist of service stations outside of the United States. These assets are expected to be disposed of in 2005.

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


	Three Months Ended
	March 31,

	2005		2004

	(Millions of dollars)
Revenues and other income	$	—	$	114
Income from discontinued operations before income tax expense		—		21
Income from discontinued operations, net of tax		—		11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

No significant gains or losses were recorded for the held-for-sale assets, including those accounted for as discontinued operations, in the 2004 and 2005 first quarters. Revenues and earnings in the comparative periods associated with held-for-sale assets not accounted for as discontinued operations were likewise insignificant.

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


Note 6.	Information Relating to the Statement of Cash Flows

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


		Three Months Ended
		March 31,

		2005			2004

		(Millions of dollars)
Increase in accounts and notes receivable		$	(1,288	)	$	(1,432	)
Increase in inventories			(113	)		(254	)
Increase in prepaid expenses and other current assets			(181	)		(22	)
Increase in accounts payable and accrued liabilities			620			886
Increase in income and other taxes payable			630			1,031

	Net (increase) decrease in operating working capital	$	(332	)	$	209

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


	Three Months Ended
	March 31,

	2005		2004

	(Millions of dollars)
Interest on debt (net of capitalized interest)	$	125	$	114
Income taxes		1,520		499

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


		Three Months Ended
		March 31,

		2005			2004

		(Millions of dollars)
Marketable securities purchased		$	(250	)	$	(353	)
Marketable securities sold			537			331

	Net sales (purchases) of marketable securities	$	287		$	(22	)

The “Net (purchases) sales of treasury shares” in 2005 included share repurchases of $708 million related to the company’s common stock repurchase program, which began in the second quarter 2004. These purchases were partially offset by the issuance of shares for the exercise of stock options.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


		Three Months Ended
		March 31,

		2005			2004

		(Millions of dollars)
Additions to properties, plant and equipment		$	1,202		$	1,222
Additions to investments			81			142
Current year dry hole expenditures			42			20
Payments for other liabilities and assets, net			(15	)		(30	)

	Capital expenditures		1,310			1,354
Other exploration expenditures			93			51

	Capital and exploratory expenditures, excluding equity affiliates	$	1,403		$	1,405
Equity in affiliates’ expenditures			293			277

	Capital and exploratory expenditures, including equity affiliates	$	1,696		$	1,682


Note 7.	Operating Segments and Geographic Data

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

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

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

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

“All Other” activities include the company’s interest in Dynegy Inc. (Dynegy), coal mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities and technology companies.

The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “international” (outside the United States).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Segment Earnings. The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All Other.” Income from continuing operations by operating segment for the three-month periods ended March 31, 2005 and 2004, is presented in the following table:

Segment Income


		Three Months Ended
		March 31,

		2005			2004

		(Millions of dollars)
Income from Continuing Operations
Upstream — Exploration and Production
	United States	$	767		$	854
	International		1,612			1,120

Total Exploration and Production			2,379			1,974

Downstream — Refining, Marketing and Transportation
	United States		58			276
	International		351			364

Total Refining, Marketing and Transportation			409			640

Chemicals
	United States		129			49
	International		8			25

Total Chemicals			137			74

Total Segment Income			2,925			2,688

All Other
	Interest Expense		(75	)		(59	)
	Interest Income		54			21
	Other		(227	)		(99	)

Income from Continuing Operations			2,677			2,551
Income from Discontinued Operations			—			11

Net Income		$	2,677		$	2,562

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Segment Assets. Segment assets do not include intercompany investments or intercompany receivables. “All Other” assets consist primarily of worldwide cash, cash equivalents and marketable securities, real estate, information systems, the company’s investment in Dynegy, coal mining operations, power generation businesses, technology companies and assets of the corporate administrative functions. Segment assets at March 31, 2005, and December 31, 2004 follow:

Segment Assets


		At March 31,		At December 31,
		2005		2004

		(Millions of dollars)
Upstream — Exploration and Production
	United States	$	11,848	$	11,869
	International		31,586		31,239

Total Exploration and Production			43,434		43,108

Downstream — Refining, Marketing and Transportation
	United States		10,527		10,091
	International		20,281		19,415

Total Refining, Marketing and Transportation			30,808		29,506

Chemicals
	United States		2,455		2,316
	International		664		667

Total Chemicals			3,119		2,983

Total Segment Assets			77,361		75,597

All Other
	United States		11,878		11,746
	International		6,564		5,865

Total All Other			18,442		17,611

Total Assets — United States			36,708		36,022
Total Assets — International			59,095		57,186

Total Assets		$	95,803	$	93,208

Segment Sales and Other Operating Revenues. Revenues for the upstream segment are derived primarily from the production of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, kerosene, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the transportation and trading of crude oil and refined products. Revenues for the chemicals segment are derived primarily from the manufacture and sale of additives for lubricants and fuel. “All Other” activities include revenues from coal mining operations, power generation businesses, insurance operations, real estate activities and technology companies.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Operating segment sales and other operating revenues, including internal transfers, for the three-month periods ended March 31, 2005 and 2004, are presented in the following table. Products are transferred between operating segments at internal product values that approximate market prices.

Sales and Other Operating Revenues


				Three Months Ended
				March 31,

				2005			2004

				(Millions of dollars)
Upstream — Exploration and Production
	United States			$	4,278		$	4,302
	International				4,729			3,922

		Sub-total			9,007			8,224
	Intersegment Elimination — United States				(1,816	)		(2,452	)
	Intersegment Elimination — International				(2,860	)		(2,083	)

			Total		4,331			3,689

Downstream — Refining, Marketing and Transportation
	United States				16,608			13,426
	International				19,143			15,566

		Sub-total			35,751			28,992
	Intersegment Elimination — United States				(44	)		(30	)
	Intersegment Elimination — International				(9	)		(15	)

			Total		35,698			28,947

Chemicals
	United States				143			124
	International				217			216

		Sub-total			360			340
	Intersegment Elimination — United States				(52	)		(39	)
	Intersegment Elimination — International				(32	)		(26	)

			Total		276			275

All Other
	United States				213			209
	International				20			30

		Sub-total			233			239
	Intersegment Elimination — United States				(94	)		(86	)
	Intersegment Elimination — International				(3	)		(1	)

			Total		136			152

Sales and Other Operating Revenues
	United States				21,242			18,061
	International				24,109			19,734

		Sub-total			45,351			37,795
	Intersegment Elimination — United States				(2,006	)		(2,607	)
	Intersegment Elimination — International				(2,904	)		(2,125	)

			Total Sales and Other Operating Revenues*	$	40,441		$	33,063


*	Includes buy/sell contracts of $5,290 and $4,256 in the 2005 and 2004 periods, respectively. Substantially all of the amount in each period related to the downstream segment. Refer to Note 15 starting on page 18 for a discussion on the company’s accounting for buy/sell contracts.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 8.	Restructuring and Reorganization Costs

In connection with various reorganizations and restructurings across several businesses and corporate departments, the company recorded before-tax charges of $258 million ($146 million after tax) during the third and fourth quarters of 2003 for estimated termination benefits for approximately 4,500 employees. Nearly half of the liability related to the global downstream segment. Substantially all of the employee reductions are expected to occur by the end of 2005.

Activity for the company’s before-tax liability related to reorganizations and restructuring for the first quarter 2005 is summarized in the following table:


	Amount

	(Millions of dollars)
Balance at January 1, 2005	$	119
Additions		—
Payments		(38	)

Balance at March 31, 2005	$	81

Substantially all of the balance at March 31, 2005, related to employee severance costs that were part of a presumed ongoing benefit arrangement under applicable accounting rules in FAS 146, “Accounting for Costs Associated with Exit or Disposal Activities,” paragraph 8, footnote 7. Therefore, the company accounts for severance costs in accordance with FAS 88, “Employers’ Accounting for Settlements and Curtailments of Defined Pension Plans and for Termination Benefits.” The amount was categorized as a current accrued liability on the Consolidated Balance Sheet and the associated charges during the period were categorized as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income.


Note 9.	Summarized Financial Data — Chevron U.S.A. Inc.

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


	Three Months Ended
	March 31,

	2005		2004

	(Millions of dollars)
Sales and other operating revenues	$	29,143	$	23,189
Costs and other deductions		28,422		21,715
Income from discontinued operations		—		6
Net income		575		1,023

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	At March 31,		At December 31,
	2005		2004

	(Millions of dollars)
Current assets	$	25,314	$	23,147
Other assets		19,900		19,961
Current liabilities		18,326		17,044
Other liabilities		12,819		12,533

Net equity	$	14,069	$	13,531

Memo: Total debt	$	8,348	$	8,349


Note 10.	Summarized Financial Data — Chevron Transport Corporation

Chevron Transport Corporation Limited (CTC), incorporated in Bermuda, is an indirect, wholly owned subsidiary of ChevronTexaco Corporation. CTC is the principal operator of ChevronTexaco’s international tanker fleet and is engaged in the marine transportation of crude oil and refined petroleum products. Most of CTC’s shipping revenue is derived by providing transportation services to other ChevronTexaco companies. ChevronTexaco Corporation has guaranteed this subsidiary’s obligations in connection with certain debt securities issued by a third party. Summarized financial information for CTC and its consolidated subsidiaries is presented as follows:


	Three Months Ended
	March 31,

	2005		2004

	(Millons of dollars)
Sales and other operating revenues	$	189	$	180
Costs and other deductions		105		123
Net income		28		53


	At March 31,		At December 31,
	2005		2004

	(Millions of dollars)
Current assets	$	512	$	292
Other assets		215		219
Current liabilities		145		67
Other liabilities		388		278

Net equity	$	194	$	166

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at March 31, 2005.


Note 11.	Income Taxes

Taxes on income from continuing operations for the first quarter 2005 were $2.2 billion, compared with $1.7 billion in last year’s first quarter. The associated effective tax rates from continuing operations for the 2005 and 2004 first quarters were 45 percent and 40 percent, respectively.

The effective tax rate for the 2005 period was higher than the rate for the comparable 2004 period primarily as a result of a higher proportion of international upstream taxable income, which is taxed at higher rates than U.S. taxable income.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 12.	Stock Options

At March 31, 2005, the company had stock-based compensation plans. The company accounts for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The following table illustrates the effect on net income and earnings per share as if the company had applied the fair-value recognition provisions of Financial Accounting Standards Board (FASB) Statement No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation:


	Three Months Ended
	March 31,

	2005			2004

	(Millions of dollars)
Net income, as reported	$	2,677		$	2,562
Add: Stock-based employee compensation expense included in reported net income determined under APB No. 25, net of related tax effects		3			—
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for awards, net of related tax effects(1)		(13	)		(6	)

Pro forma net income	$	2,667		$	2,556

Net income per share(2):
Basic — as reported	$	1.28		$	1.21
Basic — pro forma	$	1.27		$	1.21
Diluted — as reported	$	1.28		$	1.20
Diluted — pro forma	$	1.27		$	1.20


(1)	The fair value is estimated using the Black-Scholes option-pricing model for stock options. Stock appreciation rights are estimated based on the method outlined in SFAS 123 for these instruments.

(2)	2004 restated to reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.

Note 13. Employee Benefits

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

The company shares the cost of retiree medical coverage with retirees. The increase to the company contributions for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company and annual contributions reflect actual plan experience.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The components of net periodic benefit costs for the first quarters of 2005 and 2004 were:


			Three Months Ended
			March 31,

			2005			2004

			(Millions of dollars)
Pension Benefits
United States
	Service cost		$	45		$	42
	Interest cost			91			82
	Expected return on plan assets			(103	)		(87	)
	Amortization of prior-service costs			11			11
	Recognized actuarial losses			40			28
	Settlement losses			23			20

		Total United States		107			96

International
	Service cost			23			17
	Interest cost			54			43
	Expected return on plan assets			(56	)		(41	)
	Amortization of prior-service costs			4			4
	Recognized actuarial losses			14			13

		Total International		39			36

Net Periodic Pension Benefit Costs			$	146		$	132

Other Benefits*
	Service cost		$	7		$	8
	Interest cost			39			46
	Amortization of prior-service costs			(22	)		(1	)
	Recognized actuarial losses			23			7

Net Periodic Other Benefit Costs			$	47		$	60


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

At the end of 2004, the company estimated it would contribute $400 million to employee pension plans during 2005 (composed of $250 million for the U.S. plans and $150 million for the international plans). Through March 31, 2005, a total of $63 million was contributed (approximately $50 million to the U.S. plans). Estimated contributions for the full year continue to be $400 million, but the company may contribute an amount that differs from this estimate. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

During the first quarter 2005, the company contributed $55 million to its other postretirement benefit plans. The company anticipates contributing $165 million during the remainder of 2005.


Note 14.	Accounting For Suspended Exploratory Wells

In April 2005, the FASB issued a FASB Staff Position (FSP) FAS 19-1, “Accounting for Suspended Well Costs” that amends FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” The company has elected early application of this guidance with the first quarter 2005 financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

producing well and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if an enterprise obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. The FSP provides a number of indicators that can assist an entity to demonstrate sufficient progress is being made in assessing the reserves and economic viability of the project.

The following table indicates the changes to the company’s suspended exploratory well costs for the three-month period ended March 31, 2005 and for the year ended December 31, 2004:


	Three Months
	Ended		Year Ended
	March 31,		December 31,
	2005		2004

	(Millions of dollars)
Balance at beginning of period	$	671	$	549
Capitalized exploratory well costs charged to expense upon the adoption of FSP FAS 19-1		—		—
Additions to capitalized exploratory well costs pending the determination of proved reserves		75		252	*
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		—		(64	)
Capitalized exploratory well costs charged to expense		—		(66	)*

Balance at end of period	$	746	$	671


*	Amount revised by $10 million from that reported in the company’s 2004 Annual Report on Form 10-K due to changes between the draft FSP FAS 19-a and the final FSP FAS 19-1. The final FSP directs that costs suspended and expensed in the same annual period not be included in this analysis.

The following table provides an aging of capitalized well costs, based on the date the drilling was completed, and the number of projects for which exploratory well costs were capitalized for a period greater than one year since the completion of drilling:


	At March 31,		At December 31,
	2005		2004

	(Millions of dollars)
Exploratory well costs capitalized for a period of one year or less	$	294	$	222
Exploratory well costs capitalized for a period greater than one year		452		449

Balance at end of period	$	746	$	671

Number of projects with exploratory well costs that have been capitalized for a period greater than one year		24		22

Of the $746 million of total suspended costs at March 31, 2005, approximately $310 million related to 21 projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not under way or firmly planned for the near future. Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development. The $436 million balance related to wells in areas for which drilling was under way or firmly planned for the near future.

Of the $310 million referenced above, the amount capitalized in 2005 was approximately $20 million (4 projects). The $290 million balance was composed of approximately $50 million for well costs suspended in 2004 (6 projects) and $240 million suspended prior to 2004 (11 projects). The projects for the $240 million

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $75 million — discussions of joint development with an operator in an adjacent field and selection of subsurface and development plans, with front-end engineering and design (FEED) expected to begin in 2005 (one project); (b) $63 million — negotiations with contractors for FEED, negotiations with partners on equity alignment and negotiations with potential customers for natural gas (2 projects); (c) $42 million — continuation of work on FEED and finalization on all commercial terms (one project); (d) $20 million — award of detailed engineering and design contracts expected by early 2006 and discussions with host government (one project); and (e) $40 million — miscellaneous activities for projects with smaller amounts suspended. Progress is being made on all projects in this category, and the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations connected with the projects. The majority of these decisions are expected to occur in the next three years.

The $452 million of suspended well costs capitalized for a period greater than one year as of March 31, 2005 represents 40 exploratory wells in 24 projects. The table below contains the aging of these costs on a well and a project basis:

Exploratory well costs capitalized greater than one year:


		Millions of		Number of
		Dollars		Wells
Aging based on drilling completion date of individual wells:
	1994 through 1999	$	68		9
	2000 through first quarter 2004		384		31

	Total	$	452		40


				Number of
				Projects
Aging based on drilling completion date of last well in project:
	1998	$	50		1
	2000 through first quarter 2005		402		23

	Total	$	452		24


Note 15.	Accounting for Buy/ Sell Contracts

In the first quarter 2005, the SEC issued comment letters to ChevronTexaco and other companies in the oil and gas industry requesting disclosure of information related to the accounting for buy/sell contracts. Under a buy/sell contract, a company agrees to buy a specific quantity and quality of a commodity to be delivered at a specific location while simultaneously agreeing to sell a specified quantity and quality of a commodity at a different location to the same counterparty. Physical delivery occurs for each side of the transaction, and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk, and risk of nonperformance by the counterparty. Both parties settle each side of the buy/sell through separate invoicing.

The company routinely has buy/sell contracts, primarily in the United States downstream business, associated with crude oil and refined products. For crude oil, these contracts are used to facilitate the company’s crude oil marketing activity, which includes the purchase and sale of crude oil production, fulfillment of the company’s supply arrangements as to physical delivery location and crude oil specifications, and purchase of crude oil to supply the company’s refining system. For refined products, buy/sell arrangements are used to help fulfill the company’s supply agreements to customer locations and specifications.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

net on the income statement and accounted for under the provisions of Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions” (APB 29). The company understands that others in the oil and gas industry may report buy/sell transactions on a net basis in the income statement rather than gross.

The topic is under deliberation by the Emerging Issues Task Force (EITF) of the FASB as Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The EITF first discussed this issue in November 2004 and again in March 2005 when tentative conclusions were reached on the accounting for nonmonetary exchanges of inventory. Additional research is being performed by the FASB staff to explore circumstances under which two or more inventory transactions with the same counterparty (counterparties) should be viewed as a single nonmonetary transaction. This topic will be discussed again at a future EITF meeting. While this issue is under deliberation, the SEC staff directed ChevronTexaco and other companies in its first quarter 2005 comment letters to disclose on the face of the income statement the amounts associated with buy/sell contracts and to discuss in a footnote to the financial statements the basis for the underlying accounting.

With regard to the latter, the company’s accounting treatment for buy/sell contracts is based on the view that such transactions are monetary in nature. Monetary transactions are outside the scope of APB 29. The company believes its accounting is also supported by the indicators of gross reporting of purchases and sales in paragraph 3 of EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Additionally, FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (FIN 39), prohibits a receivable from being netted against a payable when the receivable is subject to credit risk unless a right of offset exists that is enforceable by law. The company also views netting the separate components of buy/sell contracts in the income statement to be inconsistent with the gross presentation that FIN 39 requires for the resulting receivable and payable on the balance sheet.

The company’s buy/sell transactions are also similar to the “barrel back” example used in other accounting literature, including EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes’ as Defined in Issue No. 02-3” (which indicates a company’s decision to show buy/sell-types of transactions gross on the income statement as being a matter of judgment of the relevant facts and circumstances of the company’s activities) and Derivatives Implementation Group (DIG) Issue No. K1, “Miscellaneous: Determining Whether Separate Transactions Should be Viewed as a Unit.”

The company further notes that the accounting for buy/sell contracts as separate purchases and sales is in contrast to the accounting for other types of contracts typically described by the industry as exchange contracts, which are considered nonmonetary in nature and appropriately shown net on the income statement. Under an exchange contract, for example, one company agrees to exchange refined products in one location for the same quantity of another company’s refined products in another location. Upon transfer, the only amounts that may be invoiced are for transportation and quality differentials. Among other things, unlike buy/sell contracts, the obligations of each party to perform under the contract are not independent and the risks and rewards of ownership are not separately transferred.

As shown on the company’s Consolidated Statement of Income, “Sales and other operating revenues” for the three-month periods ending March 31, 2005 and 2004, included $5.3 billion and $4.3 billion, respectively, for buy/sell contracts. These revenue amounts associated with buy/sell contracts represent 13 percent of total “Sales and other operating revenues” in each period. Ninety-nine percent of these revenue amounts in each period associated with buy/sell contracts pertain to the company’s downstream segment. The costs associated with these buy/sell revenue amounts are included in “Purchased crude oil and products” on the Consolidated Statement of Income in each period.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 16.	Litigation

MTBE. The company and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive.

The company is a party to more than 70 lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners, related to the use of MTBE in certain oxygenated gasolines and the alleged seepage of MTBE into groundwater. Resolution of these actions may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future.

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


Note 17.	Other Contingencies and Commitments

Income Taxes. The U.S. federal income tax liabilities have been settled through 1996 for ChevronTexaco Corporation (formerly Chevron Corporation), 1997 for ChevronTexaco Global Energy Inc. (formerly Caltex Corporation), and 1991 for Texaco Inc. The company’s California franchise tax liabilities have been settled through 1991 for Chevron and 1987 for Texaco.

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

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

Indemnifications. The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell Oil Company (Shell) and Saudi Refining Inc. in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover certain contingent liabilities, including those associated with the Unocal patent litigation. The company would be required to perform should the indemnified liabilities become actual losses. Should that occur, the company could be required to make maximum future payments of $300 million. Through March 31, 2005, the company had paid $28 million under these indemnities. Following a recently completed arbitration, Shell was awarded $10 million by an arbitrator. The company expects to receive additional requests for indemnification payments in the future.

The company has also provided indemnities relating to contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the periods of Texaco’s ownership interests in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims relating to Equilon indemnities must be asserted either as early as February 2007, or no later than February 2009, and claims relating to Motiva must be asserted no later than February 2012. Under the terms of the indemnities, there is no maximum limit on the amount of potential future payments. The company has not recorded any liabilities for possible claims under these indemnities. The company has posted no assets as collateral and has made no payments under these indemnities.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Minority Interests. The company has commitments of approximately $165 million related to minority interests in subsidiary companies.

Texaco Capital LLC, a wholly owned finance subsidiary, issued Deferred Preferred Shares, Series C, in December 1995. In February 2005, the company redeemed the last of these shares for approximately $140 million.

Environmental. The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemical or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, and land development areas, whether operating, closed or divested. These future costs are not fully determinable 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.

Although the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had or will have any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemicals companies.

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

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

One such equity redetermination process has been under way since 1996 for ChevronTexaco’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills in California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. ChevronTexaco currently estimates its maximum possible net before-tax liability at approximately $200 million. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at about $50 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

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

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


Note 18.	New Accounting Standards

FASB Statement No. 151, “Inventory Costs, an Amendment of ARB No. 43, Chapter 4” (FAS 151) In November 2004, the FASB issued FAS 151 which is effective for the company on January 1, 2006. The standard amends the guidance in Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and spoilage. In addition, the standard requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The company does not expect the clarification related to abnormal costs to have a significant impact on the company’s results of operations or financial position. The company is currently assessing its overhead allocation systems to evaluate the impact of the remaining portion of this standard.

FASB Statement No. 153, “Exchanges of Nonmonetary Assets — An Amendment of APB Opinion No. 29” (FAS 153) In December 2004, the FASB issued FAS 153, which is effective for the company for asset-exchange transactions beginning July 1, 2005. Under APB No. 29, assets received in certain types of nonmonetary exchanges were permitted to be recorded at the carrying value of the assets that were exchanged (i.e., recorded on a carryover basis). As amended by FAS 153, assets received in some circumstances will have to be recorded instead at their fair values. In the past, ChevronTexaco has not engaged in a large number of nonmonetary asset exchanges for significant amounts.

FASB Statement No. 123R, “Share-Based Payment” (FAS 123R) In December 2004, the FASB issued FAS 123R, which requires that compensation costs relating to share-based payments be recognized in the company’s financial statements. On March 29, 2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107) providing the staff’s views on the interaction between FAS 123R and certain SEC rules and regulations and on the valuation of share-based payment arrangements for public companies. The company currently accounts for share-based payments under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. In April 2005, the SEC extended the implementation date for calendar-year companies to January 1, 2006; however, the company still plans to implement FAS 123R and the guidance in SAB 107 effective July 1, 2005. The impact of adoption is expected to have a minimal impact on the company’s results of operations, financial position and liquidity. Refer to Note 12 on page 15, for the company’s calculation of the pro forma impact on net income of FAS 123, which would be similar to that under FAS 123R.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

“Accounting for Asset Retirement Obligations” (FAS 143), refers to a legal obligation to perform an asset retirement activity for which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the company. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The company does not expect that adoption of FIN 47 will have a significant effect on the company’s financial position or results of operations.

EITF Issue No. 04-6, “Accounting for Stripping Costs Incurred during Production in the Mining Industry” (Issue 04-6) In March 2005, the FASB ratified the earlier EITF consensus on Issue 04-6 which is effective for the company on January 1, 2006. Stripping costs are costs of removing overburden and other waste materials to access mineral deposits. The consensus calls for stripping costs incurred once a mine goes into production to be treated as variable production costs that should be considered a component of mineral inventory cost subject to ARB No. 43, “Restatement and Revision of Accounting Research Bulletins.” Adoption for the company’s coal and oil sands operations is not expected to significantly affect the company’s financial position or results of operations.


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

First Quarter 2005 Compared with First Quarter 2004


	*Key Financial Results*

Income From Continuing Operations by Major Operating Area


		Three Months Ended
		March 31,

		2005			2004

		(Millions of dollars)
Income from Continuing Operations
Upstream — Exploration and Production
	United States	$	767		$	854
	International		1,612			1,120

Total Upstream			2,379			1,974

Downstream — Refining, Marketing and Transportation
	United States		58			276
	International		351			364

Total Downstream			409			640

Chemicals			137			74
All Other			(248	)		(137	)

Income From Continuing Operations			2,677			2,551
Income from Discontinued Operations			—			11

Net Income(1)(2)		$	2,677		$	2,562


(1) Includes special charges:		$	—		$	(55	)
(2) Includes foreign currency effects:		$	(21	)	$	(43	)

Net income for the first quarter 2005 was $2.7 billion ($1.28 per share — diluted). Net income for the 2004 first quarter was $2.6 billion ($1.20 per share — diluted), which included a special-item charge of $55 million ($0.03 per share — diluted) for a litigation matter and income from discontinued operations of $11 million.

The special item mentioned above is identified separately because of its nature and amount to help explain the changes in net income and segment income between periods and to help distinguish the underlying trends for the company’s businesses. In the following discussions, the term “earnings” is defined as net income or segment income.

Upstream earnings in the first quarter 2005 were $2.4 billion, compared with $2 billion in the year–ago quarter. The earnings improvement was due primarily to higher prices for crude oil and natural gas, the benefits of which were partially offset by lower oil-equivalent production than in the 2004 quarter.

Average prices for U.S. crude oil and natural gas liquids increased about 28 percent from the 2004 first quarter to more than $38 per barrel. Internationally, the average price increased 38 percent to approximately $40.

Average prices for U.S. natural gas increased 10 percent between periods to about $5.75 per thousand cubic feet. Internationally, the average natural gas price increased 11 percent to nearly $3.00.

Worldwide net oil-equivalent production in the first quarter of 2005, including volumes produced from oil sands and production under an operating service agreement, declined approximately 7 percent from the first

quarter of 2004. Accounting for 6 percentage points of the 7 percent decline were the effects of property sales, cost-recovery and variable-royalty provisions of certain production contracts, and significant damage to certain producing operations in the Gulf of Mexico in the third quarter 2004 as a result of Hurricane Ivan.

Refer to pages 29 through 30 for a further discussion of upstream results in 2005 and 2004.

Downstream earnings were $409 million in the first quarter 2005, down approximately $230 million from the comparative period in 2004. The decline was largely due to the impacts of planned and unplanned downtime at several of the company’s refineries. Refer to page 30 for a further discussion of downstream results in 2005 and 2004.


	*Business Environment and Outlook*

ChevronTexaco’s current and future earnings depend largely on the profitability of its upstream and downstream business segments. The single biggest factor that affects the results of operations for upstream and downstream is the price of crude oil. Overall earnings trends are typically less affected by results from the company’s chemical business and other investments. In some reporting periods, net income can also be affected significantly by special-item gains or charges.

The company’s long-term competitive position, particularly given the capital-intensive and commodity-based nature of the industry, is closely associated with the company’s ability to invest in projects that provide adequate financial returns and to manage operating expenses effectively. Creating and maintaining an inventory of projects depends on many factors, including obtaining rights to explore, develop and produce hydrocarbons in promising areas, drilling success, the ability to bring long-lead-time capital-intensive projects to completion on budget and schedule, and efficient and profitable operation of mature properties.

The company also continuously evaluates opportunities to dispose of assets that are not key to providing sufficient long-term value and to acquire assets or operations complementary to its asset base to help sustain the company’s growth. Asset-disposition and restructuring plans may occur in future periods and result in significant gains or losses.

In early April 2005, the company announced plans to acquire Unocal Corporation for ChevronTexaco common stock and cash in a transaction valued at approximately $16.5 billion. (Refer to Note 3 on page 7 for a discussion of the agreement to acquire Unocal). Unocal’s assets complement the company’s existing upstream portfolio and ChevronTexaco’s long-term strategies to grow profitability in core upstream areas, build new legacy positions and commercialize the company’s large undeveloped natural gas resource base. The acquisition is subject to approvals by certain regulatory agencies and Unocal shareholders.

Comments related to earnings trends for the company’s major business areas are as follows:

Upstream. Changes in exploration and production earnings align most closely with industry price levels for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damages and disruptions, competing fuel prices, and regional supply interruptions that may be caused by military conflicts, civil unrest or political uncertainty. Moreover, any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments and attempts to manage risks in operating its facilities and business.

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

During 2004, industry price levels for West Texas Intermediate (WTI), a benchmark crude oil, averaged about $41 per barrel. Prices followed an upward trend in the first quarter of 2005, with WTI averaging nearly $50 per barrel, compared with $35 per barrel in the first quarter 2004. In early April 2005, industry price levels for WTI reached record highs above $57 per barrel, then declined to about $50 at the end of the month. These relatively high industry prices reflected, among other things, increased demand for crude oil from strong economic growth, particularly in Asia and the United States, the heightened level of geopolitical uncertainty in many areas of the world and supply concerns in the Middle East and other key producing regions.

During most of 2004 and into 2005, the differential in prices between high quality, light-sweet crude oils, such as the U.S. benchmark WTI, and the heavier crudes was unusually wide. The upward trend in light crude oil prices in 2004 and 2005 reflected the increased demand for light products (i.e., motor gasoline, jet fuel, aviation gasoline and diesel fuel) as all refineries can process these higher quality crudes. However, the demand and price for the heavier crudes were dampened due to the limited number of refineries that were able to process this lower quality feedstock. The company produces heavy crude oil (including volumes under an operating service agreement) in California, Chad, Indonesia, the Partitioned Neutral Zone (between Saudi Arabia and Kuwait), Venezuela and certain fields in Angola and the United Kingdom North Sea.

U.S. benchmark prices for Henry Hub natural gas averaged nearly $6.00 per thousand cubic feet (MCF) for 2004. In the first three months of 2005, the U.S. benchmark natural gas price averaged $6.33 per MCF, compared with $5.61 in the year-ago period. In early April, the Henry Hub spot price reached nearly $7.75 per MCF before falling to about $6.60 per MCF late in the month. Natural gas prices in the United States are typically higher during the winter period, when demand for heating is greatest. Additionally, natural gas price movements depend in part on the adequacy of production and storage levels to meet such demand.

As compared with the supply and demand factors for natural gas in the United States and the resultant trend in the Henry Hub benchmark prices, certain other regions of the world in which the company operates have significantly different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices for the company’s production of natural gas. (Refer to page 33 for the company’s average natural gas prices for the U.S. and international regions.) Additionally, excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the United States and other markets because of the lack of infrastructure and the difficulties in transporting natural gas.

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

In the first three months of 2005, the company’s net worldwide oil-equivalent production, including volumes produced from oil sands and production under an operating service agreement, declined about 7 percent from the year-ago period. The decrease was largely the result of property sales, production curtailments resulting from damages to producing operations caused by Hurricane Ivan in the third quarter 2004 and lower production in the United States due to normal field declines. International oil-equivalent production declined 2 percent between periods, primarily from the effect of property sales, cost recovery and variable-royalty provisions of certain production contracts.

The level of oil-equivalent production in future periods is uncertain, in part because of production quotas by OPEC and the potential for local civil unrest and changing geopolitics that could cause production disruptions. Approximately 26 percent of the company’s net oil-equivalent production in the first three months of 2005, including net barrels from oil sands and production under an operating service agreement, occurred in the OPEC-member countries of Indonesia, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. Although the company’s production level during the first three months of

2005 was not constrained in these areas by OPEC quotas, future production could be affected by OPEC-imposed limitations. Future production levels also are affected by the size and number of economic investment opportunities — including, but not limited to, the planned acquisition of Unocal — and, for new large-scale projects, the time lag between initial exploration and the beginning of production.

In certain onshore areas of Nigeria, approximately 45,000 barrels per day of the company’s net production capacity has been shut-in since March 2003 because of civil unrest and damage to production facilities. The company has adopted a phased plan to restore these operations and has begun production-resumption efforts in certain areas. While production in 2005 was not constrained in Nigeria through early May, future OPEC actions could limit the company’s ability to produce at capacity.

As a result of damages sustained from Hurricane Ivan in the Gulf of Mexico in September 2004, production in the first quarter 2005 was about 36,000 barrels per day lower than it otherwise would have been. Although most of the residual production that continues to be shut-in as a result of the storm is expected to be back on-line by the end of the second quarter 2005, ongoing facility-related expenditures relating to storm damage are likely to continue throughout the remainder of the year.

Downstream. Refining, marketing and transportation earnings are closely tied to regional demand for refined products and the associated effects on industry refining and marketing margins. The company’s core marketing areas are the West Coast of North America, the U.S. Gulf Coast, Latin America, Asia and sub-Saharan Africa.

Specific factors influencing the company’s profitability in this segment include the operating efficiencies and expenses of the refinery network, including the effects of any downtime due to planned and unplanned maintenance, refinery upgrade projects and operating incidents. The level of operating expenses can also be affected by the volatility of charter expenses for the company’s shipping operations, which are driven by the industry’s demand for crude-oil tankers. Factors beyond the company’s control include the general level of inflation, especially energy costs to operate the refinery network.

Downstream earnings declined in the first three months of 2005, compared with the year-ago quarter, largely due to the impacts associated with planned and unplanned downtime in the 2005 period at several of the company’s refineries, including the effect of the downtime on the company’s margin for refined-product sales. Company and industry margin levels may be volatile in the future, depending primarily on price movements for crude oil feedstocks, the demand for refined products, inventory levels, refinery maintenance and mishaps, and other factors.

Chemicals. Earnings in the petrochemical segment are closely tied to global chemical demand, industry inventory levels and plant capacities. Additionally, feedstock and fuel costs, which tend to follow crude oil and natural gas price movements, influence earnings in this segment.

Earnings of $137 million in the first quarter 2005 were up from the year-ago period primarily from the results of the company’s 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate, which recorded higher margins for commodity chemicals.


	*Operating Developments*

Noteworthy operating developments and events in recent months included the following:


	*Upstream*


	•	North America — Resumed production at the Petronius platform in the Gulf of Mexico in mid-March, following repairs of the significant damage caused by Hurricane Ivan in September 2004. By the end of April, the facility was producing 28,000 net oil-equivalent barrels per day. ChevronTexaco is the operator of Petronius and holds a 50 percent interest.

	•	Angola — Signed key agreements with partners to establish the gas supply, corporate structure and legal and regulatory framework for the multi-billion dollar Angola Liquefied Natural Gas (LNG) project and awarded contracts for front-end engineering and design (FEED) studies. This project will

be designed to help reduce flaring and enable commercialization of some of Angola’s vast natural gas resources. At the Sanha Field located in the Block 0 concession, offshore Cabinda province, the company produced first condensate at a total average rate of 6,000 barrels per day. Total production from the 39 percent-owned Sanha and the nearby Bomboco fields is expected to reach a maximum of approximately 100,000 barrels per day of crude oil, condensate and liquefied petroleum gas in 2006.

• Australia — Announced an agreement in principle with joint-venture participants to align equity interests in the Greater Gorgon Area, offshore Western Australia. The agreement provides the basis for the combined development of natural gas at Gorgon and nearby gas fields as one project. The company is a significant holder of natural gas resources in the area and will have a 50 percent ownership interest in the licenses for the Greater Gorgon Area.

• Libya — Announced a successful bid in Libya’s first exploration license round under the Exploration and Production Sharing Agreement IV. The company will be the operator and have a 100 percent interest in onshore Block 177.

• Nigeria — Signed a production-sharing contract for Block 1 in the Nigeria-São Tomé e Príncipe Joint Development Zone. The company will be the operator and have a 51 percent interest in the block. For the Agbami Field, the company entered into a $1.1 billion construction contract to build a floating production, storage and offloading (FPSO) vessel. The company also awarded a $1.7 billion engineering, procurement and construction contract for the Escravos gas-to-liquids project.

• Trinidad and Tobago / Venezuela — Announced the Manatee 1 natural gas discovery in Block 6d in Trinidad and Tobago waters. This well extends the area of natural gas discovered in Venezuela’s Loran Field. The company also signed a letter of intent with Spain’s Repsol YPF to pursue with the government of Venezuela new joint development activities in Venezuela’s Orinoco Belt.

• United Kingdom — Produced first crude oil from the initial development phase of the Clair Field, offshore west of the Shetland Islands. With additional development, the 19 percent-owned project is expected to average total oil-equivalent production of about 60,000 barrels per day by 2006.


	*Downstream*


	•	Asset Dispositions — Continued the marketing and sale of service station sites, with dispositions totaling nearly 1,700 sites from the program’s inception in early 2003 through the first quarter of 2005. Also in the quarter, the company sold its interest in an equity affiliate in Dubai UAE and finalized an agreement to sell service stations in Colombia. In April, the company finalized an agreement to sell approximately 120 Texaco-owned service stations in the United Kingdom and also finalized an agreement to sell its service stations in Peru.


	*Corporate*


	•	Common Stock Dividends — Announced a 12.5 percent increase in the quarterly dividend in April, marking the 18th consecutive year of increases to the annual dividend payment.

	•	Common Stock Repurchase Program — Purchased 12.4 million shares of the company’s common stock in the open market during the first quarter 2005 at a cost of $708 million. In April, an additional 5.5 million shares were purchased for $311 million. Since the inception in the second quarter 2004 of a targeted $5 billion repurchase program, more than 60 million shares have been repurchased for a total of $3.1 billion.


	*Results of Operations*

Major Business Areas. The following section presents the results of operations for the company’s business segments, as well as for the departments and companies managed at the corporate level. (Refer to Note 7 beginning on page 9 for a discussion of the company’s “reportable segments,” as defined in FAS 131, “Disclosures about Segments of an Enterprise and Related Information.”)


	*U.S. Upstream — Exploration and Production*


		Three Months Ended
		March 31,

		2005		2004

		(Millions of dollars)
	Income From Continuing Operations*	$	767	$	854
	Income From Discontinued Operations		—		6


	Segment Income*	$	767	$	860

* Includes special charges:		$	—		(55	)

U.S. exploration and production segment income was $767 million in the first quarter, down $93 million from the 2004 period. An approximate $260 million benefit from higher prices for liquids and natural gas was more than offset by lower production — resulting from property sales, the effects of Hurricane Ivan and normal field declines — and higher depreciation and depletion expense than in the first quarter 2004. The special-item charge of $55 million in the 2004 quarter related to a litigation matter.

The average liquids realization for the first quarter 2005 was $38.68 per barrel, an increase of 28 percent from $30.20 in the year-ago period. The average natural gas realization for the first quarter 2005 was $5.76 per thousand cubic feet, compared with $5.23 in the 2004 quarter.

First quarter 2005 net oil and gas production declined compared with last year’s first quarter but was essentially flat compared with the fourth quarter 2004. Net oil-equivalent production in the first quarter 2005 declined 18 percent from a year earlier to 719,000 barrels per day. The lower production in the first quarter 2005 included the effects of about 47,000 barrels per day from property sales and 36,000 barrels per day of production shut in as a result of damages from storms in the third quarter 2004. Absent the effects of property sales and storms, the decline in net oil-equivalent production was approximately 8 percent, mainly as a result of normal field declines that do not typically reverse.

The net liquids component of oil-equivalent production was down 15 percent to 452,000 barrels per day for the quarter. Excluding the effects of property sales and storm damage, first quarter 2005 net liquids production declined about 6 percent from the year-ago period. Net natural gas production in the 2005 quarter averaged 1.6 billion cubic feet per day, down about 22 percent from the 2004 period. Absent the effects of property sales and shut-in production related to storms, net natural gas production in 2005 declined 12 percent from the 2004 first quarter.


	*International Upstream — Exploration and Production*


		Three Months Ended
		March 31,

		2005			2004

		(Millions of dollars)
	Income From Continuing Operations*	$	1,612		$	1,120
	Income From Discontinued Operations		—			5


	Segment Income*	$	1,612		$	1,125

* Includes foreign currency effects		$	(18	)	$	(20	)

International exploration and production segment income increased about $500 million from the year-ago quarter to $1.6 billion. Approximately $600 million of the increase was associated with higher prices for liquids and natural gas, which was partially offset by the effect of lower oil-equivalent production. Net foreign exchange effects lowered earnings $18 million in the 2005 first quarter, about the same amount as last year’s quarter.

The average liquids realization for the first quarter 2005 quarter was $40.42 per barrel, an increase of 38 percent from $29.26 in last year’s quarter. The average natural gas realization was $2.95 per thousand cubic feet, compared with $2.67 in the 2004 quarter.

Net oil-equivalent production in the first quarter 2005 of 1.7 million barrels per day, which included 138,000 barrels per day from oil sands and production under an operating service agreement, declined about 2 percent from the year-ago period. Excluding the lower production associated with property sales and reduced volumes associated with cost-recovery and variable royalty volumes under certain production agreements, first quarter 2005 net oil-equivalent production increased approximately 3 percent.

The net liquids component of oil-equivalent production for the first quarter 2005, including volumes from oil sands and the operating service agreement, decreased about 2 percent to 1.3 million barrels per day. Excluding the effects of property sales and reduced volumes associated with cost-recovery and variable royalty volumes under certain production agreements, 2005 net liquids production increased about 3 percent from first quarter 2004, primarily from new production in China and Chad and higher production from Venezuela.

Net natural gas production of 2.2 billion cubic feet per day declined 2 percent from the first quarter 2004. Excluding the effects of property sales, first quarter 2005 natural gas production increased 3 percent from the year-ago period, primarily from higher natural gas production in Angola, Australia and Denmark.


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


	Three Months Ended
	March 31,

	2005		2004

	(Millions of dollars)
Segment Income	$	58	$	276

U.S. refining, marketing and transportation segment income declined $218 million from last year’s first quarter. The earnings decline was due primarily to lower refined-product margins for the company’s West Coast operations, which were adversely affected by significant planned and unplanned downtime at the company’s refineries in El Segundo and Richmond, California. Company margins in the East were modestly higher, despite planned downtime at the company’s Pascagoula, Mississippi, refinery. Total operating expenses were higher in the 2005 period, largely due to costs for the refinery maintenance.

Refined-product sales were essentially unchanged at 1.5 million barrels per day in the 2005 first quarter. Branded gasoline sales volumes increased 7 percent from the year-ago quarter to 583,000 barrels per day. The increase in branded gasoline sales was attributable to the reintroduction of the Texaco brand in the Southeast.


	*International Downstream — Refining, Marketing and Transportation*


		Three Months Ended
		March 31,

		2005		2004

		(Millions of dollars)
	Segment Income*	$	351	$	364


* Includes foreign currency effects		$	12	$	(25	)

International refining, marketing and transportation segment income decreased $13 million in the first quarter 2005 to $351 million. Excluding foreign currency effects in both periods, earnings declined on lower average margins. Refinery downtime also contributed to the decline.

Total refined-product sales volumes of nearly 2.3 million barrels per day were down 2 percent from the 2004 quarter, primarily on lower sales of fuel oil.


	*Chemicals*


		Three Months Ended
		March 31,

		2005			2004

		(Millions of dollars)
	Segment Income*	$	137		$	74


* Includes foreign currency effects		$	(1	)	$	(2	)

Chemical operations earned $137 million in the first quarter of 2005, compared with $74 million in the 2004 quarter. Results for the company’s 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate improved on higher margins for commodity chemicals. Partially offsetting the improved CPChem results was a decline in the earnings of the company’s Oronite subsidiary, primarily due to higher feedstock costs, lower sales volumes and costs related to unplanned downtime at the Singapore manufacturing facility.


	*All Other*


		Three Months Ended
		March 31,

		2005			2004

		(Millions of dollars)
	Net Charges*	$	(248	)	$(137)


* Includes foreign currency effects		$	(14	)	$4

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

Net charges were $248 million in the first quarter of 2005, compared with $137 million in the corresponding 2004 period. The increase in net charges was associated with higher expenses for certain corporate items and lower Dynegy earnings.


	*Consolidated Statement of Income*

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

Sales and other operating revenues for the first quarter 2005 were $40 billion, up from $33 billion in last year’s quarter. Revenues increased mainly on higher prices for crude oil, natural gas and refined products.

Income from equity affiliates increased $445 million to $889 million in the first quarter 2005. Improved earnings from Tengizchevroil, CPChem, Hamaca and the Caspian Pipeline Consortium were partially offset by lower earnings by Dynegy.

Other income of $277 million was up from $138 million in the 2004 first quarter. The first quarter 2005 period included net gains from the sale of a Canadian upstream equity investment and higher interest income as a result of higher cash and marketable securities balances compared with the year-ago period.

Purchased crude oil and products costs of $26.5 billion in the first quarter 2005 were up from $20.0 billion in the 2004 quarter. The increases between periods were primarily the result of higher prices.

Operating, selling, general and administrative expenses of $3.5 billion in the first quarter 2005 were up from $3.2 billion in the year-ago quarter. The increase included costs associated with refinery downtime and tanker chartering activity.

Exploration expenses were $153 million, compared with $85 million in the year-ago quarter. The increase was associated with well write-offs and geological and geophysical costs.

Depreciation, depletion and amortization expenses were $1.3 billion in the first quarter 2005, compared with $1.2 billion in the first quarter 2004. The increase was mainly the result of higher depreciation rates for certain producing fields worldwide.

Taxes other than on income were $5.1 billion and $4.8 billion in the first quarter of 2005 and 2004, respectively. The increase in 2005 reflected higher international taxes assessed on product values and higher duty rates in the company’s European downstream operations.

Interest and debt expense increased $14 million to $107 million in the 2005 first quarter. The modest increase in 2005 reflected lower capitalized interest, as several major projects commenced operation since last year’s first quarter.

Income tax expense from continuing operations for the first quarter 2005 was $2.2 billion, compared with $1.7 billion in last year’s first quarter. The associated effective tax rates from continuing operations for the 2005 and 2004 first quarters were 45 percent and 40 percent, respectively. The effective tax rate was higher in the 2005 period due to an increase in earnings in countries with higher tax rates.


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

ChevronTexaco owns an approximate 25 percent equity interest in the common stock of Dynegy Inc. — an energy provider engaged in power generation, gathering and processing of natural gas, and the fractionation, storage, transportation and marketing of natural gas liquids.

Investment in Dynegy Common Stock. At March 31, 2005, the carrying value of the company’s investment in Dynegy common stock was approximately $110 million. This amount was about $300 million below the company’s proportionate interest in Dynegy’s underlying net assets. This difference is primarily the result of write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value that were determined to be other than temporary. The difference has been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors giving rise to the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly when appropriate to recognize a portion of the difference between these allocated values and Dynegy’s historical book values. The market value of the company’s investment in Dynegy’s common stock at March 31, 2005, was approximately $380 million.

Investment in Dynegy Preferred Stock. The face value of the company’s investment in the Dynegy Series C preferred stock at March 31, 2005, was $400 million. The stock is accounted for at its fair value, which was estimated to be $335 million at March 31, 2005. Future temporary changes in the estimated fair values of the preferred stock will be reported in “Other comprehensive income.” However, if any future decline in fair value is deemed to be other than temporary, a charge against income in the period would be recorded. Dividends payable on the preferred stock are recognized in income each period.


	*Selected Operating Data*

The following table presents a comparison of selected operating data:

Selected Operating Data(1)(2)


			Three Months
			Ended March 31,

			2005		2004

U.S. Upstream
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			452		531
	Net Natural Gas Production (MMCFPD)(3)			1,600		2,061
	Net Oil-Equivalent Production (MBOEPD)			719		875
	Natural Gas Sales (MMCFPD)			4,920		4,585
	Natural Gas Liquids Sales (MBPD)			172		182
	Revenue from Net Production
		Liquids ($/Bbl.)	$	38.68	$	30.20
		Natural Gas ($/MCF)	$	5.76	$	5.23
International Upstream
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			1,195		1,225
	Net Natural Gas Production (MMCFPD)(3)			2,155		2,196
	Other Produced Volumes (MBPD)(4)			138		140
	Net Oil-Equivalent Production (MBOEPD)(4)			1,692		1,730
	Natural Gas Sales (MMCFPD)			1,868		1,939
	Natural Gas Liquids Sales (MBPD)			97		97
	Revenue from Liftings
		Liquids ($/Bbl.)	$	40.42	$	29.26
		Natural Gas ($/MCF)	$	2.95	$	2.67
U.S. and International Upstream
	Net Oil-Equivalent Production (MBOEPD)(3)(4)			2,411		2,605
U.S. Downstream — Refining, Marketing and Transportation
	Gasoline Sales (MBPD)(5)			698		702
	Other Refined Products Sales (MBPD)			764		759

		Total(6)		1,462		1,461
	Refinery Input (MBPD)			855		926
International Refining, Marketing and Transportation
	Gasoline Sales (MBPD)(5)			548		572
	Other Refined Products Sales (MBPD)			1,783		1,798

		Total(6)		2,331		2,370
	Refinery Input (MBPD)			1,014		1,053


(1)	Includes equity in affiliates
(2)	MBPD — Thousands of barrels per day; MMCFPD — Millions of cubic feet per day; Bbl. — Barrel; MCF — Thousands of cubic feet; Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil; MBOEPD — Thousands of barrels of oil-equivalent (BOE) per day
(3)	Includes natural gas consumed on lease (MMCFD):
	United States	52	51
	International	289	282
(4)	Includes (MBPD):
	Athabasca Oil Sands — net	26	27
	Boscan Operating Service Agreement	112	113
(5)	Includes branded and unbranded gasoline
(6)	Includes volumes for buy/sell contracts (MBPD):
	United States	85	98
	International	127	102


	*Liquidity and Capital Resources*

Cash and cash equivalents and marketable securities totaled $11.9 billion at March 31, 2005, up from $10.7 billion at year-end 2004. Cash provided by operating activities was $3.7 billion in the first three months of 2005. Operating activities in the first three months of 2005 generated funds in excess of the requirements for the company’s capital and exploratory program and payment of dividends to stockholders.

Dividends. During the first three months of 2005, the company paid dividends of $836 million to common stockholders.

Debt and Capital Lease Obligations. ChevronTexaco’s total debt and capital lease obligations were $11.1 billion at March 31, 2005, down from $11.3 billion at year-end 2004.

The company’s debt due within 12 months, consisting primarily of commercial paper and the current portion of long-term debt, totaled $5.4 billion at March 31, 2005, down from $5.6 billion at December 31, 2004. Of these amounts, $4.7 billion was reclassified to long-term at both March 31, 2005, and December 31, 2004. Settlement of these obligations is not expected to require the use of working capital in 2005, as the company has the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis. The company’s practice has been to continually refinance its commercial paper, maintaining levels management believes appropriate. In addition, the company has three existing effective “shelf” registrations on file with the SEC that together would permit additional registered debt offerings up to an aggregate $3.8 billion of debt securities.

At the end of the first quarter 2005, ChevronTexaco had $4.7 billion in committed credit facilities with various major banks, which permitted the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and also can be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on LIBOR or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at March 31, 2005.

In January 2005, the company contributed $98 million to its employee stock ownership plan (ESOP) to enable it to make a $144 million debt service payment, which included a principal payment of $113 million.

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

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

The company’s future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. Further reductions from debt balances at March 31, 2005, are dependent upon many factors including management’s continuous assessment of debt as an appropriate component of the company’s overall capital structure. The company believes it has substantial borrowing capacity to meet unanticipated cash requirements, and, during periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, the company believes that it has the flexibility to increase borrowings and/or modify capital spending plans to continue paying the common stock dividend and maintain the company’s high-quality debt ratings.

Current Ratio — current assets divided by current liabilities. The current ratio was 1.6 at March 31, 2005, compared with 1.5 at December 31, 2004. The current ratio is adversely affected because the company’s inventories are valued on a LIFO basis. At year-end 2004, inventories were lower than replacement costs, based on average acquisition costs during the year, by approximately $3 billion. The company does not consider its inventory valuation methodology to affect liquidity.

Debt Ratio — total debt as a percentage of total debt plus equity. This ratio was approximately 19 percent at March 31, 2005, compared with 20 percent at year-end 2004 and 25 percent at March 31, 2004.

Common Stock Repurchase Program. The company announced a common stock repurchase program on March 31, 2004. Acquisitions of up to $5 billion will be made from time to time at prevailing prices as permitted by securities laws and other legal requirements, and subject to market conditions and other factors. The program will occur over a period of up to three years and may be discontinued at any time. The company purchased 54,679,000 shares in the open market for $2.8 billion through March 2005. Purchases during April increased the total shares acquired to 60,159,000 for a total of $3.1 billion.

Pension Obligations. At the end of 2004, the company estimated it would contribute $400 million to employee pension plans during 2005 (composed of $250 million for the U.S. plans and $150 million for the international plans). Through March 31, 2005, a total of $63 million was contributed (approximately $50 million to the U.S. plans). Estimated contributions for the full year continue to be $400 million, but the company may contribute an amount that differs from this estimate. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

Capital and exploratory expenditures. Total expenditures, including the company’s share of spending by affiliates, were $1.7 billion in the first three months of 2005, essentially unchanged from the corresponding 2004 period. The amounts included the company’s share of affiliate expenditures of about $300 million in the 2005 and 2004 periods. Expenditures for exploration and production projects were approximately $1.3 billion — comprising about 80 percent of the total expenditures — reflecting the company’s continued emphasis on profitably growing its upstream businesses.

Capital and Exploratory Expenditures by Major Operating Area


			Three Months
			Ended March 31,

			2005		2004

United States
	Upstream — Exploration and Production		$	386	$	424
	Downstream — Refining, Marketing and Transportation			111		53
	Chemicals			19		27
	All Other			83		207

		Total United States		599		711

International
	Upstream — Exploration and Production			941		877
	Downstream — Refining, Marketing and Transportation			148		90
	Chemicals			7		2
	All Other			1		2

		Total International		1,097		971

		Worldwide	$	1,696	$	1,682


	*Contingencies and Significant Litigation*

MTBE. The company and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive.

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

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

Accounting for Buy/Sell Contracts. In the first quarter 2005, the SEC issued comment letters to ChevronTexaco and other companies in the oil and gas industry requesting disclosure of information related to the accounting for buy/sell contracts. Under a buy/sell contract, a company agrees to buy a specific quantity and quality of a commodity to be delivered at a specific location while simultaneously agreeing to sell a specified quantity and quality of a commodity at a different location to the same counterparty. Physical delivery occurs for each side of the transaction, and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk, and risk of nonperformance by the counterparty. Both parties settle each side of the buy/sell through separate invoicing.

The company accounts for buy/sell transactions in the Consolidated Statement of Income the same as any other monetary transaction for which title passes, and the risks and rewards of ownership are assumed by the counterparties. At issue with the SEC is whether the accounting for buy/sell contracts should be shown net on the income statement and accounted for under the provisions of Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions” (APB 29). The company understands that others in the oil and gas industry may report buy/sell transactions on a net basis in the income statement rather than gross.

The company’s buy/sell transactions are also similar to the “barrel back” example used in other accounting literature, including EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3” (which indicates a company’s decision to show buy/sell-types of transactions gross on the income statement as being a matter of judgment of the relevant facts and circumstances of the company’s activities) and Derivatives Implementation Group (DIG) Issue No. K1, “Miscellaneous: Determining Whether Separate Transactions Should be Viewed as a Unit.”

Accounting for Suspended Exploratory Wells. In April 2005, the FASB issued a FASB Staff Position (FSP) FAS 19-1 “Accounting for Suspended Well Costs” that amends FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” The company has elected for early application of this guidance with the first quarter 2005 financial statements.

Under the provisions of the FSP FAS 19-1, exploratory well costs continue to be capitalized after the completion of drilling when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if an enterprise obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. The FSP provides a number of indicators that can assist an entity to demonstrate sufficient progress is being made in assessing the reserves and economic viability of the project.


	*New Accounting Standards*

have to be recorded instead at their fair values. In the past, ChevronTexaco has not engaged in a large number of nonmonetary asset exchanges for significant amounts.

FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47) In March 2005, the FASB issued FIN 47, which is effective for the company on December 31, 2005. FIN 47 clarifies that the phrase “conditional asset retirement obligation,” as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143), refers to a legal obligation to perform an asset retirement activity for which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the company. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The company does not expect that adoption of FIN 47 will have a significant effect on the company’s financial position or results of operations.


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

Information about market risks for the three months ended March 31, 2005, does not differ materially from that discussed under Item 7A of ChevronTexaco’s Annual Report on Form 10-K for 2004.


Item 4.	*Controls and Procedures*

(a) Evaluation of disclosure controls and procedures

ChevronTexaco Corporation’s Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the company’s “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of March 31, 2005, have concluded that as of March 31, 2005, the company’s disclosure controls and procedures were effective and designed to provide reasonable assurance that material information relating to the company and its consolidated subsidiaries required to be included in the company’s periodic filings under the Exchange Act would be made known to them by others within those entities.

(b) Changes in internal control over financial reporting

During the quarter ended March 31, 2005, there were no changes in the company’s internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, the company’s internal control over financial reporting.

PART II

OTHER INFORMATION


Item 1.	*Legal Proceedings*

None.


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

CHEVRONTEXACO CORPORATION

ISSUER PURCHASES OF EQUITY SECURITIES

Maximum

Total Number of

Number of Shares

Total Number

Average

Shares Purchased as

that May Yet Be

of Shares

Price Paid

Part of Publicly

Purchased Under

Period

Purchased(1)

per Share

Announced Program

the Program

Jan. 1-Jan. 31, 2005

3,653,658

51.74

2,907,000

—

Feb. 1-Feb. 28, 2005

3,482,080

56.81

2,738,000

—

Mar. 1-Mar. 31, 2005

7,284,526

60.02

6,710,000

—

Total

14,420,264

57.15

12,355,000

)


(1)	Includes 230,189 common shares repurchased during the three-month period ended March 31, 2005 from company employees for required personal income tax withholdings on the individual’s exercise of the stock options issued to management and employees under the company’s broad-based employee stock options, long-term incentive plans and former Texaco Inc. stock option plans. Additionally, includes 1,835,075 shares delivered or attested to in satisfaction of the exercise price by holders of certain former Texaco Inc. employee stock options exercised during the three-month period ended March 31, 2005.

(2)	On March 31, 2004, the company announced a common stock repurchase program. Acquisitions of up to $5 billion will be made from time to time at prevailing prices as permitted by securities laws and other requirements, and subject to market conditions and other factors. The program will occur over a period of up to three years and may be discontinued at any time. Through March 31, 2005, $2.8 billion had been expended to repurchase 54,679,000 shares since the common stock repurchase program began.


Item 5.	*Other Information*


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

No change.


	*Rule 10b5-1 Plan Elections*

No rule 10b5-1 plans were adopted for the period that ended on March 31, 2005.


Item 6.	*Exhibits*


Exhibit
Number		Description

(2)		ChevronTexaco Corporation and Unocal Corporation Agreement and Plan of Merger, dated April 4, 2005, filed as Exhibit 2.1 to ChevronTexaco’s Current Report on Form 8-K dated April 7, 2005, and incorporated herein by reference.
(4)		Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the company and its subsidiaries on a consolidated basis. A copy of any such instrument will be furnished to the Commission upon request.
(10.13)		Summary of ChevronTexaco Management Incentive Plan Awards and Criteria
(10.14)		Chevron Corporation Change in Control Surplus Employee Severance Program For E-Level Salary Grades
(10.15)		Chevron Corporation Benefit Protection Program
(12.1)		Computation of Ratio of Earnings to Fixed Charges
(31.1)		Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer
(31.2)		Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer
(32.1)		Section 1350 Certification by the company’s Chief Executive Officer
(32.2)		Section 1350 Certification by the company’s Chief Financial Officer

SIGNATURE

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


		Chevrontexaco Corporation


	(Registrant)


	/s/ M.A. Humphrey

	M.A. Humphrey, Vice President and Comptroller
	(Principal Accounting Officer and
	Duly Authorized Officer)

Date: May 4, 2005

EXHIBIT INDEX


Exhibit
Number		Description

(2)		ChevronTexaco Corporation and Unocal Corporation Agreement and Plan of Merger, dated April 4, 2005, filed as Exhibit 2.1 to ChevronTexaco’s Current Report on Form 8-K dated April 7, 2005, and incorporated herein by reference.
(4)		Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the company and its subsidiaries on a consolidated basis. A copy of any such instrument will be furnished to the Commission upon request.
(10.13)*		Summary of ChevronTexaco Management Incentive Plan Awards and Criteria
(10.14)*		Chevron Corporation Change in Control Surplus Employee Severance Program For E-Level Salary Grades
(10.15)*		Chevron Corporation Benefit Protection Program
(12.1)*		Computation of Ratio of Earnings to Fixed Charges
(31.1)*		Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer
(31.2)*		Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer
(32.1)*		Section 1350 Certification by the company’s Chief Executive Officer
(32.2)*		Section 1350 Certification by the company’s Chief Financial Officer


*	Filed herewith.

Copies of above exhibits not contained herein are available, to any security holder upon written request to the Corporate Governance Department, ChevronTexaco Corporation, 6001 Bollinger Canyon Road, San Ramon, California 94583.


		be designed to help reduce flaring and enable commercialization of some of Angola’s vast natural gas resources. At the Sanha Field located in the Block 0 concession, offshore Cabinda province, the company produced first condensate at a total average rate of 6,000 barrels per day. Total production from the 39 percent-owned Sanha and the nearby Bomboco fields is expected to reach a maximum of approximately 100,000 barrels per day of crude oil, condensate and liquefied petroleum gas in 2006.

	•	Australia — Announced an agreement in principle with joint-venture participants to align equity interests in the Greater Gorgon Area, offshore Western Australia. The agreement provides the basis for the combined development of natural gas at Gorgon and nearby gas fields as one project. The company is a significant holder of natural gas resources in the area and will have a 50 percent ownership interest in the licenses for the Greater Gorgon Area.

	•	Libya — Announced a successful bid in Libya’s first exploration license round under the Exploration and Production Sharing Agreement IV. The company will be the operator and have a 100 percent interest in onshore Block 177.

	•	Nigeria — Signed a production-sharing contract for Block 1 in the Nigeria-São Tomé e Príncipe Joint Development Zone. The company will be the operator and have a 51 percent interest in the block. For the Agbami Field, the company entered into a $1.1 billion construction contract to build a floating production, storage and offloading (FPSO) vessel. The company also awarded a $1.7 billion engineering, procurement and construction contract for the Escravos gas-to-liquids project.

	•	Trinidad and Tobago / Venezuela — Announced the Manatee 1 natural gas discovery in Block 6d in Trinidad and Tobago waters. This well extends the area of natural gas discovered in Venezuela’s Loran Field. The company also signed a letter of intent with Spain’s Repsol YPF to pursue with the government of Venezuela new joint development activities in Venezuela’s Orinoco Belt.

	•	United Kingdom — Produced first crude oil from the initial development phase of the Clair Field, offshore west of the Shetland Islands. With additional development, the 19 percent-owned project is expected to average total oil-equivalent production of about 60,000 barrels per day by 2006.