Chevron 10Q 2005 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

		For the quarterly period ended June 30, 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

Chevron Corporation

(Exact name of registrant as specified in its charter)


Delaware		94-0890210
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

6001 Bollinger Canyon Road,
San Ramon, California		94583-2324
(Address of principal executive offices)		(Zip Code)

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

ChevronTexaco Corporation

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

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

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

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


Class		Outstanding as of June 30, 2005
Common stock, $.75 par value		2,083,964,951

INDEX


		Page
		No.

	Cautionary Statements Relevant to Forward-Looking Information for the Purpose of “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		2
PART I FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements —
	Consolidated Statement of Income for the Three and Six Months Ended June 30, 2005, and 2004		3
	Consolidated Statement of Comprehensive Income for the Three and Six Months Ended June 30, 2005, and 2004		4
	Consolidated Balance Sheet at June 30, 2005, and December 31, 2004		5
	Consolidated Statement of Cash Flows for the Six Months Ended June 30, 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		24-41
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		42
Item 4.	Controls and Procedures		42

PART II OTHER INFORMATION
Item 1.	Legal Proceedings		43
Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		43
Item 4.	Submission of Matters to a Vote of Security Holders		44
Item 5.	Other Information		46
Item 6.	Exhibits		46
Signature			47
Rule 13a-14(a)/15d-14(a) Certifications			55-56
Section 1350 Certifications			57-58
EXHIBIT 3.2
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 Chevron Corporation contains forward-looking statements relating to Chevron’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, Chevron 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 merger with 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*

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF INCOME

(Unaudited)


			Three Months Ended				Six Months Ended
			June 30				June 30

			2005		2004		2005		2004

			(Millions of dollars, except per-share amounts)
Revenues and Other Income
Sales and other operating revenues(1)(2)			$	47,247	$	36,579	$	87,688	$	69,642
Income from equity affiliates				861		740		1,750		1,184
Other income				235		924		512		1,062

	Total Revenues and Other Income			48,343		38,243		89,950		71,888

Costs and Other Deductions
Purchased crude oil and products(2)				31,130		22,452		57,621		42,479
Operating expenses				2,713		2,234		5,182		4,401
Selling, general and administrative expenses				1,152		986		2,151		2,007
Exploration expenses				139		165		292		250
Depreciation, depletion and amortization				1,320		1,243		2,654		2,433
Taxes other than on income(1)				5,311		4,889		10,437		9,654
Interest and debt expense				104		94		211		187
Minority interests				18		18		39		40

	Total Costs and Other Deductions			41,887		32,081		78,587		61,451

Income From Continuing Operations Before Income Tax Expense				6,456		6,162		11,363		10,437
Income tax expense				2,772		2,056		5,002		3,780

Income From Continuing Operations				3,684		4,106		6,361		6,657
Income From Discontinued Operations				—		19		—		30

Net Income			$	3,684	$	4,125	$	6,361	$	6,687

Per Share of Common Stock(3):
	Income From Continuing Operations
		—Basic	$	1.77	$	1.93	$	3.05	$	3.14
		— Diluted	$	1.76	$	1.93	$	3.04	$	3.13
	Income From Discontinued Operations
		—Basic	$	—	$	0.01	$	—	$	0.01
		— Diluted	$	—	$	0.01	$	—	$	0.01
	Net Income
		—Basic	$	1.77	$	1.94	$	3.05	$	3.15
		— Diluted	$	1.76	$	1.94	$	3.04	$	3.14
	Dividends		$	0.45	$	0.37	$	0.85	$	0.73
	Weighted Average Number of Shares Outstanding (000s)
		— Basic		2,077,743		2,122,715		2,084,141		2,124,725
		— Diluted		2,085,763		2,127,344		2,092,792		2,129,040


(1) Includes consumer excise taxes:	$	2,162	$	1,921	$	4,278	$	3,778
(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:	$	5,962	$	4,637	$	11,337	$	8,893
(3) 2004 periods 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.

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Unaudited)


			Three Months Ended						Six Months Ended
			June 30						June 30

			2005			2004			2005			2004

			(Millions of dollars)
Net Income			$	3,684		$	4,125		$	6,361		$	6,687

	Currency translation adjustment			8			5			5			6
	Unrealized holding gain (loss) on securities			24			(6	)		(9	)		1
	Net derivatives loss on hedge transactions:
		Before income taxes		(48	)		(23	)		(38	)		(19	)
		Income taxes		16			—			14			(2	)

		Total		(32	)		(23	)		(24	)		(21	)
	Minimum pension liability adjustment			—			3			1			3

Other Comprehensive Loss, net of tax				—			(21	)		(27	)		(11	)

Comprehensive Income			$	3,684		$	4,104		$	6,334		$	6,676

See accompanying notes to consolidated financial statements.

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

At June 30

At December 31

2005

2004

(Millions of dollars, except

per-share amounts)

ASSETS

Cash and cash equivalents

12,317

9,291

Marketable securities

1,160

1,451

Accounts and notes receivable, net

14,844

12,429

Inventories:

Crude oil and petroleum products

2,681

2,324

Chemicals

206

173

Materials, supplies and other

466

486

Total inventories

3,353

2,983

Prepaid expenses and other current assets

2,269

2,349

Total Current Assets

33,943

28,503

Long-term receivables, net

1,400

1,419

Investments and advances

14,856

14,389

Properties, plant and equipment, at cost

106,356

103,954

Less: accumulated depreciation, depletion and amortization

61,687

59,496

Properties, plant and equipment, net

44,669

44,458

Deferred charges and other assets

4,050

4,277

Assets held for sale

122

162

Total Assets

99,040

93,208

LIABILITIES AND STOCKHOLDERS’ EQUITY

Short-term debt

647

816

Accounts payable

12,424

10,747

Accrued liabilities

2,788

3,410

Federal and other taxes on income

3,344

2,502

Other taxes payable

1,424

1,320

Total Current Liabilities

20,627

18,795

Long-term debt

10,310

10,217

Capital lease obligations

312

239

Deferred credits and other noncurrent obligations

8,185

7,942

Noncurrent deferred income taxes

7,539

7,268

Reserves for employee benefit plans

3,379

3,345

Minority interests

153

172

Total Liabilities

50,505

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 June 30, 2005, and December 31, 2004)

1,706

1,706

Capital in excess of par value

4,206

4,160

Retained earnings

50,008

45,414

Accumulated other comprehensive loss

(346

)

(319

)

Deferred compensation and benefit plan trust

(494

)

(607

)

Treasury stock, at cost (190,067,063 and 166,911,890 shares at June 30, 2005, and December 31, 2004, respectively)

(6,545

)

(5,124

)

Total Stockholders’ Equity

48,535

45,230

Total Liabilities and Stockholders’ Equity

99,040

93,208

See accompanying notes to consolidated financial statements.

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)


				Six Months Ended
				June 30

				2005			2004

				(Millions of dollars)
Operating Activities
	Net income			$	6,361		$	6,687
	Adjustments
		Depreciation, depletion and amortization			2,654			2,433
		Dry hole expense			81			106
		Distributions less than income from equity affiliates			(529	)		(906	)
		Net before-tax gains on asset retirements and sales			(110	)		(948	)
		Net foreign currency effects			(20	)		(2	)
		Deferred income tax provision			514			294
		Net (increase) decrease in operating working capital			(611	)		264
		Minority interest in net income			39			40
		(Increase) decrease in long-term receivables			(25	)		128
		Decrease in other deferred charges			191			558
		Cash contributions to employee pension plans			(93	)		(594	)
		Other			161			(129	)

			Net Cash Provided by Operating Activities		8,613			7,931

Investing Activities
		Capital expenditures			(3,174	)		(2,974	)
		Proceeds from asset sales			593			1,500
		Net sales of marketable securities			286			3
		Repayment of loans by equity affiliates			90			75

			Net Cash Used for Investing Activities		(2,205	)		(1,396	)

Financing Activities
		Net borrowings of short-term obligations			103			35
		Proceeds from issuance of long-term debt			20			—
		Repayments of long-term debt and other financing obligations			(110	)		(421	)
		Cash dividends			(1,770	)		(1,550	)
		Dividends paid to minority interests			(28	)		(3	)
		Net purchases of treasury shares			(1,375	)		(423	)
		Redemption of preferred stock of subsidiary			(140	)		—

			Net Cash Used For Financing Activities		(3,300	)		(2,362	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents					(82	)		(100	)

Net Change in Cash and Cash Equivalents					3,026			4,073
Cash and Cash Equivalents at January 1					9,291			4,266

Cash and Cash Equivalents at June 30				$	12,317		$	8,339

See accompanying notes to consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1.	Interim Financial Statements

On May 9, 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. The accompanying consolidated financial statements of Chevron Corporation and its subsidiaries (the company) have not been audited by independent accountants. In the opinion of the company’s management, the interim data include all adjustments necessary for a fair statement of the results for the interim periods. These adjustments were of a normal recurring nature, except for the items described in Note 2.

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- and six-month periods ended June 30, 2005, are not necessarily indicative of future financial results.


Note 2.	Net Income

Net income for the second quarter 2005 was $3.7 billion compared with $4.1 billion in the 2004 second quarter. Included in the 2004 results were a special-item gain of $585 million related to the sale of upstream assets in western Canada and a one-time benefit of $255 million associated with a change in income-tax laws in certain international operations.

Net income for the first six months of 2005 was $6.4 billion compared with $6.7 billion in the year-ago period. Besides the second quarter items in 2004, the year-to-date amount included a special-item charge of $55 million for a litigation matter.

Foreign currency effects increased earnings by $54 million and $45 million in the second quarters of 2005 and 2004, respectively. For the six months of 2005 and 2004, foreign currency effects increased earnings by $33 million and $2 million, respectively.


Note 3.	Agreement to Acquire Unocal

On April 4, 2005, Chevron announced plans to acquire Unocal Corporation (Unocal) in a stock and cash transaction. On June 29, 2005, the U.S. Securities and Exchange Commission (SEC) declared effective the company’s registration statement. On July 19, Chevron revised the terms of its original offer to a stock and cash transaction valued at approximately $17 billion for accounting purposes under FAS 141,“Business Combinations.” On August 2, 2005, the Federal Trade Commission announced its approval of two final consent orders dated as of July 27, 2005, relating to the merger.

With the actions by the SEC and FTC, no other U.S. regulatory clearances are needed prior to the consummation of the merger, if the transaction is approved by Unocal stockholders on August 10, 2005.

For additional information on this planned acquisition, refer to the company’s Registration Statement, Amendment No. 3, on Form S-4 filed with the U.S. Securities and Exchange Commission on June 28, 2005, and the Current Report on Form 8-K filed with the U.S. Securities and Exchange Commission on July 25, 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5.	Assets Held for Sale and Discontinued Operations

At June 30, 2005, and December 31, 2004, the company classified $122 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				Six Months Ended
	June 30				June 30

	2005		2004		2005		2004

			(Millions of dollars)
Revenues and other income	$	—	$	147	$	—	$	261
Income from discontinued operations before income tax expense		—		38		—		59
Income from discontinued operations, net of tax		—		19		—		30

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:


		Six Months Ended
		June 30

		2005			2004

		(Millions of dollars)
Increase in accounts and notes receivable		$	(2,477	)	$	(1,938	)
Increase in inventories			(370	)		(563	)
(Increase) decrease in prepaid expenses and other current assets			(52	)		36
Increase in accounts payable and accrued liabilities			1,251			1,062
Increase in income and other taxes payable			1,037			1,667

	Net (increase) decrease in operating working capital	$	(611	)	$	264

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


	Six Months Ended
	June 30

	2005		2004

	(Millions of dollars)
Interest on debt (net of capitalized interest)	$	210	$	195
Income taxes		3,533		1,875

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


		Six Months Ended
		June 30

		2005			2004

		(Millions of dollars)
Marketable securities purchased		$	(503	)	$	(622	)
Marketable securities sold			789			625

	Net sales of marketable securities	$	286		$	3

The “Net sales of treasury shares” in 2005 included share repurchases of $1.5 billion 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.

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


		Six Months Ended
		June 30

		2005			2004

		(Millions of
		dollars)
Additions to properties, plant and equipment		$	2,926		$	2,699
Additions to investments			231			241
Current year dry hole expenditures			60			86
Payments for other liabilities and assets, net			(43	)		(52	)

	Capital expenditures		3,174			2,974
Other exploration expenditures			211			144
Payments of capital lease obligations			142			1

	Capital and exploratory expenditures, excluding equity affiliates		3,527			3,119
Equity in affiliates’ expenditures			695			636

	Capital and exploratory expenditures, including equity affiliates	$	4,222		$	3,755


Note 7.	Operating Segments and Geographic Data

Although each subsidiary of Chevron is responsible for its own affairs, Chevron 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 Chevron 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

“All Other” activities include the company’s interest in Dynegy Inc. (Dynegy), coal mining operations, power 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- and six-month periods ended June 30, 2005 and 2004, is presented in the following table:

Segment Income


		Three Months Ended						Six Months Ended
		June 30						June 30

		2005			2004			2005			2004

		(Millions of dollars)
Income from Continuing Operations
Upstream — Exploration and Production
	United States	$	972		$	948		$	1,739		$	1,802
	International		1,800			2,016			3,412			3,136

Total Exploration and Production			2,772			2,964			5,151			4,938

Downstream — Refining, Marketing and Transportation
	United States		398			517			456			793
	International		578			527			929			891

Total Refining, Marketing and Transportation			976			1,044			1,385			1,684

Chemicals
	United States		63			40			192			89
	International		21			19			29			44

Total Chemicals			84			59			221			133

Total Segment Income			3,832			4,067			6,757			6,755

All Other
	Interest Expense		(73	)		(60	)		(148	)		(119	)
	Interest Income		60			24			114			45
	Other		(135	)		75			(362	)		(24	)

Income from Continuing Operations			3,684			4,106			6,361			6,657
Income from Discontinued Operations			—			19			—			30

Net Income		$	3,684		$	4,125		$	6,361		$	6,687

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 June 30, 2005, and December 31, 2004 follow:

Segment Assets


		At June 30		At December 31
		2005		2004

		(Millions of dollars)
Upstream — Exploration and Production
	United States	$	12,086	$	11,869
	International		32,294		31,239

Total Exploration and Production			44,380		43,108

Downstream — Refining, Marketing and Transportation
	United States		10,831		10,091
	International		20,825		19,415

Total Refining, Marketing and Transportation			31,656		29,506

Chemicals
	United States		2,497		2,316
	International		694		667

Total Chemicals			3,191		2,983

Total Segment Assets			79,227		75,597

All Other
	United States		11,816		11,746
	International		7,997		5,865

Total All Other			19,813		17,611

Total Assets — United States			37,230		36,022
Total Assets — International			61,810		57,186

Total Assets		$	99,040	$	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- and six-month periods ended June 30, 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						Six Months Ended
				June 30						June 30

				2005			2004			2005			2004

				(Millions of dollars)
Upstream — Exploration and Production
	United States			$	5,219		$	3,844		$	9,497		$	8,146
	International				5,399			4,315			10,128			8,237

		Sub-total			10,618			8,159			19,625			16,383
	Intersegment Elimination — United States				(2,052	)		(1,911	)		(3,868	)		(4,363	)
	Intersegment Elimination — International				(3,051	)		(2,678	)		(5,911	)		(4,761	)

			Total		5,515			3,570			9,846			7,259

Downstream — Refining, Marketing and Transportation
	United States				19,573			15,390			36,181			28,816
	International				21,739			17,260			40,882			32,826

		Sub-total			41,312			32,650			77,063			61,642
	Intersegment Elimination — United States				(48	)		(62	)		(92	)		(92	)
	Intersegment Elimination — International				—			(12	)		(9	)		(27	)

			Total		41,264			32,576			76,962			61,523

Chemicals
	United States				157			131			300			255
	International				233			211			450			427

		Sub-total			390			342			750			682
	Intersegment Elimination — United States				(61	)		(44	)		(113	)		(83	)
	Intersegment Elimination — International				(32	)		(28	)		(64	)		(54	)

			Total		297			270			573			545

All Other
	United States				283			240			496			449
	International				21			34			41			64

		Sub-total			304			274			537			513
	Intersegment Elimination — United States				(127	)		(110	)		(221	)		(196	)
	Intersegment Elimination — International				(6	)		(1	)		(9	)		(2	)

			Total		171			163			307			315

Sales and Other Operating Revenues
	United States				25,232			19,605			46,474			37,666
	International				27,392			21,820			51,501			41,554

		Sub-total			52,624			41,425			97,975			79,220
	Intersegment Elimination — United States				(2,288	)		(2,127	)		(4,294	)		(4,734	)
	Intersegment Elimination — International				(3,089	)		(2,719	)		(5,993	)		(4,844	)

			Total Sales and Other Operating Revenues*	$	47,247		$	36,579		$	87,688		$	69,642


*	Includes buy/sell contracts of $5,962 and $4,637 in the 2005 and 2004 second quarters, respectively, and $11,337 and $8,893 in the 2005 and 2004 six-month periods, respectively. Substantially all of the amount in

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	each period related to the downstream segment. Refer to Note 15 on page 18 for a discussion on the company’s accounting for buy/sell contracts.


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 in 2005 is summarized in the following table:


	Amount

	(Millions of dollars)
Balance at January 1, 2005	$	119
Additions		4
Payments		(51	)

Balance at June 30, 2005	$	72

Substantially all of the balance at June 30, 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 Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’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 Chevron. CUSA also holds Chevron’s investments in the Chevron Phillips Chemical Company LLC (CPChem) joint venture and Dynegy, which are accounted for using the equity method.


	Six Months Ended
	June 30

	2005		2004

	(Millions of dollars)
Sales and other operating revenues	$	63,353	$	50,098
Costs and other deductions		60,710		46,596
Income from discontinued operations		—		12
Net income		1,855		2,350

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	At June 30		At December 31
	2005		2004

	(Millions of dollars)
Current assets	$	27,239	$	23,147
Other assets		19,948		19,961
Current liabilities		18,991		17,044
Other liabilities		12,831		12,533

Net equity	$	15,365	$	13,531

Memo: Total debt	$	8,349	$	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 Chevron Corporation. CTC is the principal operator of Chevron’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 Chevron companies. Chevron Corporation has guaranteed this subsidiary’s obligations in connection with certain debt securities issued by a third party. Summarized financial information for CTC and its consolidated subsidiaries is presented as follows:


	Three Months Ended				Six Months Ended
	June 30				June 30

	2005		2004		2005		2004

	(Millions of dollars)
Sales and other operating revenues	$	143	$	142	$	332	$	322
Costs and other deductions		125		119		230		242
Net income		6		22		34		75


	At June 30		At December 31
	2005		2004

	(Millions of dollars)
Current assets	$	472	$	292
Other assets		287		219
Current liabilities		138		67
Other liabilities		421		278

Net equity	$	200	$	166

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at June 30, 2005.


Note 11.	Income Taxes

Taxes on income from continuing operations for the second quarter and first half of 2005 were $2.8 billion and $5.0 billion, respectively, compared with $2.1 billion and $3.8 billion for the comparable periods in 2004. The associated effective tax rates for the 2005 and 2004 second quarters were 43 percent and 33 percent, respectively. For the year-to-date periods, the effective tax rates were 44 percent and 36 percent, respectively.

The effective tax rates for the three- and six-month periods of 2005 were higher than the corresponding 2004 periods due to an increase in international earnings in countries with higher tax rates. In addition, the effective tax rates for the three- and six-month periods of 2004 benefited from a change in income tax laws for certain international operations and the effect of the Canadian capital gains tax rate on the sale of upstream assets in western Canada.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 12.	Stock Options

At June 30, 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					Six Months Ended
	June 30					June 30

	2005			2004		2005		2004

	(Millions of dollars)
Net income, as reported	$	3,684		$	4,125	$	6,361	$	6,687
Add: Stock-based employee compensation expense included in reported net income determined under APB No. 25, net of related tax effects		(1	)		—		2		—
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for awards, net of related tax effects(1)		11			7		24		13

Pro forma net income	$	3,672		$	4,118	$	6,339	$	6,674

Net income per share:(2)
Basic — as reported	$	1.77		$	1.94	$	3.05	$	3.15
Basic — pro forma	$	1.77		$	1.94	$	3.04	$	3.14
Diluted — as reported	$	1.76		$	1.94	$	3.04	$	3.14
Diluted — pro forma	$	1.76		$	1.94	$	3.03	$	3.13


(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.

The company plans to adopt FASB Statement No. 123R,“Share-Based Payment,” in the quarterly reporting period ending September 30, 2005. Refer to the discussion of this implementation plan in Note 18 on page 22. In accordance with FAS 123R implementation guidance recently issued by the staff of the Securities and Exchange Commission, the company will change its practice for determining the stock-option vesting period for retirement-eligible employees. For the calculation of stock-option expense on a pro forma basis under APB 25, the company accelerated the vesting period for such employees only upon their actual retirement and in accordance with provisions of the company’s stock-based compensation programs. For the calculation of expense upon adoption of FAS 123R, the vesting period for such employees will be accelerated to the date under the program rules at which the employees can receive the stock option award without further company service, whether or not the employees actually retire at that date. The difference in expense between these two methods of determining the vesting periods is not significant to any period presented in the table above.


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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 for the major U.S. plan. Certain life insurance benefits are paid by the company and annual contributions reflect actual plan experience.

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


			Three Months Ended						Six Months Ended
			June 30						June 30

			2005			2004			2005			2004

			(Millions of dollars)
Pension Benefits
United States
	Service cost		$	46		$	43		$	91		$	85
	Interest cost			92			83			183			165
	Expected return on plan assets			(105	)		(90	)		(208	)		(177	)
	Amortization of prior-service costs			11			10			22			21
	Recognized actuarial losses			39			28			79			56
	Settlement losses			29			24			52			44

		Total United States		112			98			219			194

International
	Service cost			19			18			42			35
	Interest cost			44			46			98			89
	Expected return on plan assets			(48	)		(44	)		(104	)		(85	)
	Amortization of transitional assets			1			1			1			1
	Amortization of prior-service costs			4			4			8			8
	Recognized actuarial losses			11			13			25			26
	Curtailment losses			—			2			—			2
	Termination benefit recognition			—			1			—			1

		Total International		31			41			70			77

Net Periodic Pension Benefit Costs			$	143		$	139		$	289		$	271

Other Benefits*
	Service cost		$	7		$	8		$	14		$	16
	Interest cost			39			47			78			93
	Amortization of prior-service costs			(23	)		—			(45	)		(1	)
	Recognized actuarial losses			23			5			46			12

Net Periodic Other Benefit Costs			$	46		$	60		$	93		$	120


*	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).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Through June 30, 2005, a total of $93 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 half of 2005, the company contributed about $110 million to its other postretirement benefit plans. The company anticipates contributing an additional $110 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 elected 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.

The company’s suspended well costs at June 30, 2005 were $808 million, an increase of $137 million from year-end 2004 due to drilling activities in several countries. For the category of exploratory well costs at year-end 2004 that were suspended more than one year, $2 million was expensed in the first half 2005.


Note 15.	Accounting for Buy/ Sell Contracts

In the first quarter 2005, the SEC issued comment letters to Chevron 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.

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. In its June 2005 meeting, the EITF reached a tentative conclusion that inventory purchase and sales transactions with the same counterparty that are entered into in contemplation of one another should be combined for purposes of applying APB 29. The EITF has issued a draft abstract for comments from interested parties and plans to discuss comments received at its September 2005 meeting. While this issue is under deliberation, the SEC staff directed Chevron 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 six-month periods ending June 30, 2005 and 2004, included $11.3 billion and $8.9 billion, respectively, for buy/sell contracts. These revenue amounts associated with buy/sell contracts represented 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.


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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 Chevron Corporation (formerly ChevronTexaco Corporation), 1997 for Chevron 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 June 30, 2005, the company had paid $38 million under these indemnities. 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 period 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, nor has the company posted any assets as collateral or made any payments under these indemnities.

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

Minority Interests The company has commitments of approximately $150 million related to minority interests in subsidiary companies.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 Chevron 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.

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 Chevron’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. Chevron 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 Chevron is estimated at about $50 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 will 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, Chevron 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 plans to adopt FAS 123R and the guidance in SAB 107 in the third quarter 2005 using the modified prospective method. The impact of adoption is anticipated to have a minimal impact on the company’s results of operations, financial position and liquidity. Refer to Note 12 on page 16 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.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

fair value of an asset retirement obligation. The company does not expect that adoption of FIN 47 will have a significant effect on its 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.”The company does not anticipate adoption of this accounting for its coal and oil sands operations will have a significant effect on the company’s financial position or results of operations.


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

Second Quarter 2005 Compared with Second Quarter 2004

and First Half 2005 Compared with First Half 2004


	*Key Financial Results*

Income From Continuing Operations by Major Operating Area


		Three Months Ended					Six Months Ended
		June 30					June 30

		2005			2004		2005			2004

		(Millions of dollars)
Income from Continuing Operations
Upstream — Exploration and Production
	United States	$	972		$	948	$	1,739		$	1,802
	International		1,800			2,016		3,412			3,136

Total Upstream			2,772			2,964		5,151			4,938

Downstream — Refining, Marketing and Transportation
	United States		398			517		456			793
	International		578			527		929			891

Total Downstream			976			1,044		1,385			1,684

Chemicals			84			59		221			133
All Other			(148	)		39		(396	)		(98	)

Income From Continuing Operations			3,684			4,106		6,361			6,657
Income From Discontinued Operations — Upstream			—			19		—			30

Net Income(1)(2)		$	3,684		$	4,125	$	6,361		$	6,687


(1) Includes foreign currency effects		$	54		$	45	$	33		$	2
(2) Includes income from special items			—			585		—			530

Net incomefor the 2005 second quarter was $3.7 billion ($1.76 per share — diluted). Net income for the 2004 second quarter was $4.1 billion ($1.94 per share — diluted), which included a special-item gain of $0.6 billion ($0.28 per share) related to the sale of upstream assets in western Canada and a one-time benefit of $0.2 billion ($0.12 per share) associated with a change in income tax laws for certain international operations.

Net income for the first six months of 2005 was $6.4 billion ($3.04 per share — diluted). Net income in the corresponding 2004 period was $6.7 billion ($3.14 per share — diluted), which included $0.8 billion ($0.37 per share) of benefits for the effect of special items and the tax-law change.

The special items mentioned above are identified separately because of their 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 earningsin the second quarter 2005 were $2.8 billion, compared with $3.0 billion in the year-ago period, which included a benefit of $0.8 billion for the effect of special items and the tax-law change. Earnings for the first half 2005 were $5.2 billion, vs. $4.9 billion a year earlier, which included a benefit of $0.7 billion for the effect of special items and the tax-law change.

Earnings in the quarterly and six-month 2005 periods benefited from higher average prices for crude oil and natural gas. Lower oil-equivalent production in 2005 served to partially offset the benefit of these higher prices.

Average U.S. prices in the 2005 quarter for crude oil and natural gas liquids increased 35 percent from a year earlier to about $44 per barrel. Average prices for the six months increased 32 percent to more than $41. Internationally, average prices increased about 40 percent in both periods to $45 for the quarter and $43 for the six months.

Average U.S. prices for natural gas in the second quarter 2005 increased 13 percent to about $6.30 per thousand cubic feet. For the six months, prices increased 12 percent to about $6.00. Internationally, the average price increased 18 percent to $3.00 for the quarter and 14 percent to nearly $3.00 in the first half.

Worldwide net oil-equivalent production, including volumes produced from oil sands and production under an operating service agreement, declined approximately 6 percent between quarters and 7 percent for the six months. A majority of the decline in both periods was associated with the effects of property sales and higher prices on the calculation of cost-recovery volumes under the production-sharing contract in Indonesia.

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

Downstream earningswere $976 million in the second quarter 2005, a decline of $68 million from the year-ago period. Six-month 2005 earnings were $1.4 billion, down from $1.7 billion in the 2004 first half. Lower earnings in both periods were due mainly to the impact of refinery downtime for maintenance and repairs. Refer to pages 30 - 31 for a further discussion of downstream results in 2005 and 2004.


	*Business Environment and Outlook*

Chevron’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 both segments is the movement in the price of crude oil. In the downstream business, crude oil is the largest cost component of refined products. 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 investment projects depends on many factors, including obtaining rights to explore for oil and gas, developing and producing hydrocarbons in promising areas, drilling successfully, bringing long-lead-time capital-intensive projects to completion on budget and schedule, and operating mature upstream properties efficiently and profitably.

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 April 2005, the company announced plans to acquire Unocal Corporation for Chevron common stock and cash valued at $16.7 billion. In June, the two companies agreed to a consent order issued by the U.S. Federal Trade Commission (FTC) if the business combination were approved by the Unocal stockholders, and the U.S. Securities and Exchange Commission (SEC) declared effective the Chevron registration statement for the issuance of the necessary common stock for the acquisition. In July, Chevron revised the terms of its original offer to a stock and cash transaction valued at $17.3 billion. On August 2, 2005, the FTC announced its approval of two final consent orders dated as of July 27, 2005, relating to the merger. The acquisition is subject to approval by Unocal stockholders at a meeting on August 10, 2005. Unocal’s assets complement Chevron’s existing upstream portfolio and fit the company’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.

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 six months of 2005, with WTI averaging about $52 per barrel, compared with $37 per barrel in the first half 2004. During July, WTI averaged $59 per barrel. The rise in crude oil prices is reflective of, 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 into light-product fuels. 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 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 six months of 2005, the U.S. benchmark natural gas price averaged $6.66, compared with $5.88 in the year-ago period. During July, the spot price averaged about $7.60 per MCF. 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 natural-gas production. (Refer to page 34 for the company’s average natural gas prices for the U.S. and international regions.) Additionally, excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the United States and other markets because of the lack of infrastructure and the difficulties in transporting natural gas.

To help address this regional imbalance between supply and demand for natural gas, Chevron 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, along with 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 six 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, cost-recovery and variable-royalty provisions of certain production agreements, production curtailments resulting from damages to producing operations caused by Hurricane Ivan in September 2004 and lower production in the United States due to normal field declines. Absent the effects of property sales, storms and the cost-recovery provisions, net production declined about 2 percent between periods. (Refer also to the Results of Operations on pages 29 - 30 for further discussions of U.S. and international production trends.)

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 half 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 six 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 40,000 barrels per day of the company’s net production capacity have 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 July, 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 was lower than otherwise would have been in the second quarter and first half of 2005 by approximately 15,000 and 26,000 barrels per day, respectively. Most of the shut-in production resulting from damages sustained from Hurricane Ivan was back on-line by the end of the second quarter 2005.

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 were lower in the second quarter and first-half 2005 compared with the year-ago periods largely due to the impacts associated with planned and unplanned downtime at several of the company’s refineries, including the effect of the downtime on the company’s refined-product sales margins. 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.

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

Earnings of $84 million in the second quarter 2005 were up from the year-ago period. Six-month profits of $221 million increased nearly $90 million from the previous year. Earnings for the company’s 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate increased from higher margins for commodity chemicals compared with the year-ago periods.


	*Operating Developments*

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


	*Upstream*


	•	Decision to expand the North West Shelf onshore liquefied natural gas (LNG) facilities in Western Australia. The $1.5 billion project includes adding a fifth LNG train that will increase export capacity by 4.2 million metric tons per year to approximately 16 million. Chevron holds a one-sixth interest in the North West Shelf LNG facilities.

	•	Award of exploration rights to four deepwater blocks in the northern Carnarvon Basin offshore Western Australia. Located in an area of significant natural gas potential, Chevron will operate and own 50 percent interest in the blocks located in the same petroleum basin as the North West Shelf and Greater Gorgon resources.

	•	Decision to move the Australian Greater Gorgon gas development project into the front-end engineering and design phase. The development will establish a two-train (10 million metric tons per year) LNG facility and potential domestic gas plant on Barrow Island. Chevron has a 50 percent ownership interest in the licenses for the Greater Gorgon Area.

	•	Discovery of natural gas offshore Venezuela in Block 3 of Plataforma Deltana. The discovery is adjacent to the Loran gas field in Block 2 and provides sufficient resources for a detailed evaluation of Venezuela’s first LNG train.

	•	Order of two LNG carriers to support the planned growth in the company’s LNG business. Each carrier will have a 155,000 cubic meter capacity and be company-operated. The carriers will complement the development of Chevron’s LNG export and import terminals worldwide.


	*Downstream*


	•	Project to increase the capacity of the Pascagoula, Mississippi, refinery’s fluid catalytic cracking unit. The project will be designed to increase plant capacity by 25 percent from a current level of 60,000 barrels per day, enabling greater production of gasoline and other light products.

	•	Sale of more than 100 company-owned service stations in the United Kingdom. Under the terms of the sales agreement, Chevron will continue to supply the service stations with fuel.


	*Corporate*


	•	Repurchase of common stock. The company acquired 27.4 million shares of its common stock in the open market during the first six months of 2005 at a cost of $1.5 billion, including more than $800 million worth in the second quarter. Since the inception of a $5 billion repurchase program in April 2004, the company has acquired 69.7 million of its shares for a total of $3.6 billion.


	*Results of Operations*

Major Business AreasThe 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				Six Months Ended
		June 30				June 30

		2005		2004		2005		2004

		(Millions of dollars)
	Income From Continuing Operations*	$	972	$	948	$	1,739	$	1,802
	Income From Discontinued Operations		—		7		—		13

	Segment Income*	$	972	$	955	$	1,739	$	1,815


*Includes special charges		$	—	$	—	$	—	$	(55	)

U.S. upstream segment income was $972 million in the second quarter, up marginally from the 2004 period. An approximate $365 million benefit from higher prices for liquids and natural gas was largely offset by lower production — resulting from property sales, the effects of Hurricane Ivan and normal field declines — and higher depreciation expense.

For the six-month period, income was $1.7 billion, compared with $1.8 billion a year earlier. A benefit of approximately $630 million from higher prices for liquids and natural gas was essentially offset by lower production and higher depreciation expense. The six-month 2004 results included a special charge of $55 million due to an adverse litigation matter.

The average liquids realization for the second quarter was $44.07 per barrel, an increase of about 35 percent from $32.68 in the year-ago period. For the comparative six-month periods, the average realization of $41.44 per barrel was up 32 percent from $31.45. The average natural gas realization for the second quarter 2005 was $6.31 per thousand cubic feet, compared with $5.59 in the 2004 quarter. Year-to-date, the average realization was $6.04, compared with $5.40 in 2004.

Second quarter 2005 net oil-equivalent production declined 15 percent from a year earlier to 740,000 barrels per day. Year-to-date, net oil-equivalent production declined by 16 percent to 729,000 barrels per day. Production was lower in the 2005 second quarter and six-month periods by approximately 42,000 and 43,000 barrels per day, respectively, due to the effect of property sales and by 15,000 and 26,000 barrels per day, respectively, as a result of storm damages to producing facilities. Absent the effects of property sales and storms, the decline was 8 percent and 9 percent from the year-earlier quarterly and first-half periods, respectively, due mainly to normal field declines that typically do not reverse.

The net liquids component of oil-equivalent production was down 12 percent to 470,000 barrels per day for the quarter and down 14 percent to 461,000 barrels per day for the six-month period. Excluding the effects of property sales and storm damage, second quarter 2005 and year-to-date net liquids production declined about 6 percent from the corresponding 2004 periods.

Net natural gas production averaged about 1.6 billion cubic feet per day for the 2005 second quarter and six months, down approximately 19 percent and 21 percent from the year-ago periods, respectively. Absent the effects of property sales and shut-in production related to storms, net natural gas production in 2005 declined 11 percent and 12 percent from the 2004 second quarter and year-to-date periods, respectively.


	*International Upstream — Exploration and Production*


		Three Months Ended				Six Months Ended
		June 30				June 30

		2005		2004		2005		2004

		(Millions of dollars)
	Income From Continuing Operations(1)(2)	$	1,800	$	2,016	$	3,412	$	3,136
	Income From Discontinued Operations		—		12		—		17

	Segment Income(1)(2)	$	1,800	$	2,028	$	3,412	$	3,153


(1) Includes foreign currency effects		$	57	$	22	$	39	$	2
(2) Includes special gains			—		585		—		585

International upstream segment income was $1.8 billion in the second quarter 2005, compared with $2.0 billion in the year-ago period, which included a special-item gain of $585 million for the sale of producing properties in western Canada and a one-time benefit of $208 million related to a change in certain income-tax laws. Higher average prices for crude oil and natural gas increased 2005 earnings by about $565 million.

First-half 2005 earnings were $3.4 billion, vs. $3.1 billion in the corresponding 2004 period, which had the same $0.8 billion benefit from special items and the tax-law change as the second quarter. Higher average prices for crude oil and natural gas contributed about $1.2 billion to higher earnings in 2005. This benefit was partially offset by the effect of lower oil-equivalent production.

The average liquids realization for the second quarter 2005 was $45.19 per barrel, an increase of 39 percent from $32.48 a year earlier. For the first-half 2005, the average realization was $42.81, compared with $30.90 for the six-months 2004. The average natural gas realization for the second quarter 2005 was $3.01 per thousand cubic feet, up from $2.55 in the 2004 quarter. Between six-month periods, the average natural gas realization increased 14 percent to $2.98.

Net oil-equivalent production for both the second quarter and first-half 2005 was 1.7 million barrels per day, including volumes from oil sands and production under an operating service agreement. This was about 2 percent lower than the corresponding periods in 2004. Excluding the lower volumes associated with property sales and cost-recovery provisions of the Indonesian production-sharing contract, production increased about 2 percent in both periods.

The net liquids component of oil-equivalent production for the second quarter 2005 decreased about 3 percent from a year ago to 1.3 million barrels per day. Excluding the effects of property sales and cost-recovery volumes, production increased about 1 percent on higher production levels in China, Republic of the Congo, the Karachaganak Field in Kazakhstan, and in Venezuela that were partially offset by the effects of a turnaround for scheduled maintenance at Tengizchevroil in Kazakhstan. For the first six months of 2005, liquids production decreased about 2 percent to 1.3 million barrels per day. Excluding the effects of property sales and cost-recovery volumes, production increased about 2 percent from last year’s first six months.

Net natural gas production of 2.2 billion cubic feet per day in the second quarter and first-half 2005 was essentially unchanged from the year-ago periods. Excluding the effects of property sales, natural gas production increased about 6 percent and 1 percent from the 2004 second quarter and six months, respectively.


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

Three Months Ended

Six Months Ended

June 30

2005

2004

2005

2004

(Millions of dollars)

Segment Income

398

517

456

793

U.S. downstream segment income declined $119 million from last year’s second quarter to $398 million, due mainly to the effects of refinery downtime for maintenance and repairs. Average refined-products margins for operations on the West Coast were also lower in 2005. For the first-half 2005, earnings were $456 million,

compared with $793 million in the corresponding 2004 period. Downtime for refinery maintenance and repairs was the primary factor in the earnings decline.

Refined-product sales decreased 3 percent to 1.5 million barrels per day in the 2005 second quarter. Six-month sales of 1.5 million barrels per day were about 1 percent lower than the first-half 2004. Although sales of fuel oil and jet fuel were lower in both periods, branded gasoline sales increased as a result of the reintroduction of the Texaco brand.


	*International Downstream — Refining, Marketing and Transportation*


		Three Months Ended				Six Months Ended
		June 30				June 30

		2005		2004		2005		2004

		(Millions of dollars)
	Segment Income*	$	578	$	527	$	929	$	891


* Includes foreign currency effects		$	12	$	27	$	24	$	2

International downstream segment income increased $51 million in the 2005 second quarter to $578 million. The 2004 period included a one-time benefit of $47 million for a change in certain income-tax laws. Excluding this benefit, the improvement between periods resulted primarily from higher average refined-product margins in most of the company’s operating areas and an increase in the ownership percentage of the Singapore Refining Company. Partially offsetting these benefits were the effects of downtime for repairs at the company’s Pembroke, U.K., refinery. Earnings for the six months of 2005 were $929 million, up $38 million from the 2004 first half. As for the second quarter change, the benefit of higher margins was partially offset by the effects of increased refinery downtime.

Total refined-product sales volumes of 2.3 million barrels per day in the 2005 quarter were about 5 percent lower. For the first six months, refined-product sales volumes decreased about 4 percent. The sales decline in the quarter was primarily the result of lower gasoline trading activity and expiration of certain fuel oil contracts. For the six months, fuel oil sales were lower.


	*Chemicals*


		Three Months Ended						Six Months Ended
		June 30						June 30

		2005			2004			2005			2004

		(Millions of dollars)
	Segment Income*	$	84		$	59		$	221		$	133


* Includes foreign currency effects		$	(1	)	$	(2	)	$	(2	)	$	(4	)

Chemical operations earned $84 million in the second quarter of 2005, compared with $59 million in the 2004 period. For the six months, earnings increased $88 million to $221 million. Results for the company’s 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) affiliate improved in both periods on higher margins for commodity chemicals. Partially offsetting were lower results in both periods for the company’s Oronite subsidiary, due mainly to increased costs associated with feedstocks used in manufacturing.


	*All Other*


		Three Months Ended						Six Months Ended
		June 30						June 30

		2005			2004			2005			2004

		(Millions of dollars)
	Net (Charges) Income*	$	(148	)	$	39		$	(396	)	$	(98	)


* Includes foreign currency effects		$	(14	)	$	(2	)	$	(28	)	$	2

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 $148 million in the second quarter of 2005, compared with income of $39 million in the corresponding 2004 period. The 2004 second quarter included a gain on an asset sale and an income tax benefit. The increase in net charges in the 2005 second quarter and year-to-date periods otherwise was associated with higher expenses for a number of corporate items that individually were not significant and lower earnings by the company’s Dynegy affiliate.

For further information on the Dynegy affiliate, refer to “Information Relating to the Company’s Investment in Dynegy” beginning on page 33.


	*Consolidated Statement of Income*

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

Sales and other operating revenuesfor the second quarter 2005 were $47 billion, up from $37 billion in the 2004 second quarter. For the first-half 2005, sales and operating revenues were $88 billion, vs. $70 billion in 2004. Revenues in both periods increased mainly on higher prices for crude oil, natural gas and refined products.

Income from equity affiliatesincreased $121 million to $861 million in the second quarter 2005. For the six-month period, the increase was $566 million to nearly $1.8 billion. Improved earnings from the Tengizchevroil, CPChem, Hamaca and Escravos gas-to-liquids affiliates and the Singapore Refining Company were partially offset by lower results from Dynegy, the Caspian Pipeline Consortium and Caltex Australia Ltd.

Other incomeof $235 million in the 2005 second quarter was $689 million lower than the 2004 period. For the first-half 2005, other income was $512 million, compared with approximately $1.1 billion in 2004. Both periods in 2004 included net gains from asset sales, including an approximate $700 million special item related to the sale of upstream assets in western Canada.

Purchased crude oil and productscosts of $31 billion in the second quarter 2005 were up from $22 billion in the 2004 quarter. For the six-month period, such costs were $58 billion, up from $42 billion. The increase in both periods was the result of higher prices for crude oil, natural gas and refined products.

Operating, selling, general and administrative expensesof $3.9 billion in the second quarter 2005 were up from $3.2 billion in the year-ago quarter. For the six months 2005, such expenses were $7.3 billion, compared with $6.4 billion last year. Both the quarterly and six-month periods included higher costs for refinery repairs and maintenance, pipeline transportation, chartering of crude-oil tankers, the company’s employee stock-ownership plan and a number of corporate items that individually were not significant.

Exploration expenseswere $139 million in the second quarter 2005, down $26 million from a year earlier on reduced amounts for well write-offs. For the six-month periods, exploration expenses increased $42 million to $292 million on higher amounts for well write-offs and costs of geological, geophysical and seismic data for international operations.

Depreciation, depletion and amortization expenseswere $1.3 billion in the second quarter 2005, compared with $1.2 billion in the second quarter 2004. For the six-months of 2005 and 2004, expenses were $2.7 billion and $2.4 billion, respectively. The increase in both periods was mainly the result of higher depreciation rates for certain oil and gas producing fields worldwide.

Taxes other than on incomewere $5.3 billion and $4.9 billion in the second quarter of 2005 and 2004, respectively. For the six-month periods, expenses were $10.4 billion and $9.7 billion in 2005 and 2004, respectively. The increase in 2005 primarily reflected higher international taxes assessed on product values and higher duty rates in the company’s European downstream operations and higher U.S. federal excise taxes on jet fuel resulting from a change in tax law that became effective in 2005.

Interest and debt expenseincreased $10 million between quarters to $104 million in 2005 and by $24 million from last year’s first half to $211 million. The increases were primarily due to a reduction in the interest capitalized on major investment projects. Average interest rates were also higher on the company’s commercial paper borrowings.

Income tax expensefrom continuing operations for the second quarter and first-half 2005 was $2.8 billion and $5 billion, respectively, vs. $2.1 billion and $3.8 billion for the comparable periods in 2004. The associated effective tax rates from continuing operations for the 2005 and 2004 second quarters were 43 and 33 percent, respectively. For the year-to-date periods, the effective tax rates were 44 and 36 percent, respectively. Rates were higher in both 2005 periods due mainly to an increase in earnings in countries with higher tax rates. The 2004 periods had a one-time benefit associated with a tax-law change for certain international operations, as well as the effect of a favorable capital-gains rate being applicable to the large gain on the sale of upstream assets in western Canada.


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

Chevron owns an approximate 25 percent equity interest in the common stock of Dynegy Inc. (Dynegy) — 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 June 30, 2005, the carrying value of the company’s investment in Dynegy common stock was approximately $130 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 June 30, 2005, was approximately $470 million.

Investment in Dynegy Preferred Stock. The face value of the company’s investment in the Dynegy Series C preferred stock at June 30, 2005, was $400 million. The stock is accounted for at its fair value, which was estimated to be $370 million at June 30, 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 were 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.

Dynegy Announcement of Asset Sale. On August 2, 2005, Dynegy announced the sale of its midstream assets for approximately $2.5 billion. Chevron anticipates recording a significant gain in the fourth quarter 2005 for its equity share of the after-tax income recognized by Dynegy.


	*Selected Operating Data*

The following table presents a comparison of selected operating data:

Selected Operating Data(1)(2)


			Three Months Ended				Six Months Ended
			June 30				June 30

			2005		2004		2005		2004

U.S. Upstream
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			470		535		461		534
	Net Natural Gas Production (MMCFPD)(3)			1,621		2,001		1,611		2,031
	Net Oil-Equivalent Production (MBOEPD)			740		869		729		873
	Sales of Natural Gas (MMCFPD)(4)			5,697		4,425		5,281		4,505
	Sales of Natural Gas Liquids (MBPD)			170		177		171		180
	Revenue from Net Production
		Liquids ($/Bbl.)	$	44.07	$	32.68	$	41.44	$	31.45
		Natural Gas ($/MCF)	$	6.31	$	5.59	$	6.04	$	5.40
International Upstream
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			1,179		1,214		1,187		1,219
	Net Natural Gas Production (MMCFPD)(3)			2,151		2,124		2,153		2,160
	Net Oil-Equivalent Production (MBOEPD)(5)			1,681		1,710		1,687		1,720
	Sales of Natural Gas (MMCFPD)			1,842		1,850		1,845		1,894
	Sales of Natural Gas Liquids (MBPD)			101		113		98		105
	Revenue from Liftings
		Liquids ($/Bbl.)	$	45.19	$	32.48	$	42.81	$	30.90
		Natural Gas ($/MCF)	$	3.01	$	2.55	$	2.98	$	2.61
U.S. and International Upstream
	Total Net Oil-Equivalent Production, including Other Produced Volumes (MBOEPD)(3)(5)			2,421		2,579		2,416		2,593
U.S. Downstream — Refining, Marketing and Transportation
	Gasoline (MBPD)(6)			714		685		706		693
	Other Refined Products (MBPD)			796		866		780		813

		Total(7)		1,510		1,551		1,486		1,506
	Refinery Input (MBPD)			912		969		884		945
	Average Refined Product Sales Price ($/Bbl.)		$	66.18	$	50.79	$	61.67	$	48.02
International Downstream — Refining, Marketing and Transportation
	Gasoline (MBPD)(6)			566		644		557		608
	Other Refined Products (MBPD)			1,761		1,812		1,772		1,805

		Total(7)		2,327		2,456		2,329		2,413
	Refinery Input (MBPD)			1,007		1,063		1,010		1,060
	Average Refined Product Sales Price ($/Bbl.)		$	67.04	$	49.53	$	63.19	$	48.12


(1)	Includes equity in affiliates
(2)	MBPD = thousand barrels per day; MMCFPD = million cubic feet per day; Bbl. = barrel; MCF = thousand cubic feet; Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil; MBOEPD = thousands of barrels of oil-equivalent (BOE) per day
(3)	Includes natural gas consumed on lease (MMCFPD):
	United States	58	51	55	51
	International	225	270	256	276
(4)	2004 conformed to 2005 presentation
(5)	Includes other produced volumes (MBPD):
	Athabasca oil sands — net	32	28	29	28
	Boscan Operating Service Agreement	111	114	111	113

		143	142	140	141
(6)	Includes branded and unbranded gasoline
(7)	Includes volumes for buy/sell contracts (MBPD):
	United States	78	85	81	91
	International	137	104	137	103


	*Liquidity and Capital Resources*

Cash and cash equivalents and marketable securitiestotaled $13.5 billion at June 30, 2005, up from $10.7 billion at year-end 2004. Cash provided by operating activities was $8.6 billion in the first six months of 2005. Operating activities in the first six 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 six months of 2005, the company paid dividends of $1.8 billion to common stockholders.

Debt and Capital Lease Obligations Chevron’s total debt and capital lease obligations were $11.3 billion at June 30, 2005, unchanged from 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 $5.5 billion at June 30, 2005, down from $5.6 billion at December 31, 2004. Of these amounts, $4.9 billion and $4.7 billion were reclassified to long-term at June 30, 2005, and December 31, 2004, respectively. 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 second quarter 2005, Chevron had $4.9 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 June 30, 2005.

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.

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, Chevron 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.

Chevron’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. Chevron’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and Prime 1 by Moody’s, and the company’s Canadian commercial paper is rated R-1 (middle) by Dominion Bond Rating Service. All of these ratings denote high-quality, investment-grade securities.

The company’s future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. Further reductions from debt balances at June 30, 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 June 30, 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 19 percent at June 30, 2005, compared with 20 percent at year-end 2004 and 23 percent at June 30, 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. During the first six months of 2005, 27.4 million shares were purchased in the open market at a cost of $1.5 billion. Since the inception of the program in April 2004, the company had purchased 69.7 million shares for $3.6 billion through June 2005.

Pension ObligationsAt 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 June 30, 2005, a total of $93 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 expendituresTotal expenditures, including the company’s share of spending by affiliates, were $4.2 billion in the first six months of 2005, compared with $3.8 billion in the corresponding 2004 period. The amounts included the company’s share of affiliate expenditures of $695 million and $635 million in the 2005 and 2004 periods, respectively. Expenditures for exploration and production projects in 2005 were about $3.3 billion, representing about 80 percent of the companywide total. About three-fourths of this upstream amount was for projects outside the United States, reflecting the company’s continued emphasis on international crude oil and natural gas production activities.

Capital and Exploratory Expenditures by Major Operating Area


			Three Months Ended				Six Months Ended
			June 30				June 30

			2005		2004		2005		2004

			(Millions of dollars)
United States
	Upstream — Exploration and Production		$	538	$	472	$	924	$	896
	Downstream — Refining, Marketing and Transportation			122		86		233		139
	Chemicals			24		34		43		61
	All Other			97		103		180		310

		Total United States		781		695		1,380		1,406

International
	Upstream — Exploration and Production			1,388		1,151		2,329		2,028
	Downstream — Refining, Marketing and Transportation			333		221		481		311
	Chemicals			8		6		15		8
	All Other			16		—		17		2

		Total International		1,745		1,378		2,842		2,349

		Worldwide	$	2,526	$	2,073	$	4,222	$	3,755


	*Contingencies and Significant*

MTBEThe 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.

Income TaxesThe U.S. federal income tax liabilities have been settled through 1996 for Chevron Corporation (formerly ChevronTexaco Corporation), 1997 for Chevron 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.

GuaranteesThe 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.

IndemnificationsThe 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 June 30, 2005, the company had paid $38 million under these indemnities. The company expects to receive additional requests for indemnification payments in the future.

EnvironmentalThe 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.

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

Global OperationsChevron 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.

Equity RedeterminationFor 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 Chevron’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. Chevron 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 Chevron is estimated at about $50 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

Other ContingenciesChevron 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.

Accounting for Buy/ Sell ContractsIn the first quarter 2005, the SEC issued comment letters to Chevron 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.

that others in the oil and gas industry may report buy/sell transactions on a net basis in the income statement rather than gross.


	*New Accounting Standards*

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 will 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, Chevron has not engaged in a large number of nonmonetary asset exchanges for significant amounts.


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

Information about market risks for the three months ended June 30, 2005, does not differ materially from that discussed under Item 7A of Chevron’s Annual Report on Form 10-K for 2004.


Item 4.	*Controls and Procedures*

(a) Evaluation of disclosure controls and procedures

Chevron Corporation’s Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the company’s “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of June 30, 2005, have concluded that as of June 30, 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 June 30, 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*


	*El Segundo Refinery — Alleged Air Violations*

The South Coast Air Quality Management District (AQMD) has issued several notices of violations to Chevron Products Company, a division of Chevron U.S.A. Inc, alleging over 160 violations of the AQMD’s Rule 463, which regulates emissions from floating roof tanks, at the company’s El Segundo, California, Refinery. The company is in settlement discussions with the AQMD, which are expected to result in the payment of a civil penalty of $100,000 or more.


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

CHEVRON CORPORATION

ISSUER PURCHASES OF EQUITY SECURITIES

Maximum

Total Number of

Number of Shares

Total Number

Average

Shares Purchased as

that May Yet Be

of Shares

Price Paid

Part of Publicly

Purchased Under

Period

Purchased(1)

per Share

Announced Program

the Program

Apr. 1-Apr. 30, 2005

5,622,474

56.70

5,480,000

—

May 1-May 31, 2005

4,772,795

52.67

4,549,000

—

Jun. 1-Jun. 30, 2005

5,759,318

57.18

5,013,400

—

Total

16,154,587

55.68

15,042,400

)


(1)	Includes 78,484 common shares repurchased during the three-month period ended June 30, 2005, from company employees for required personal income tax withholdings on the 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. Also includes 1,033,703 shares delivered or attested to in satisfaction of the exercise price by holders of certain former Texaco Inc. employee stock options exercised during the three-month period ended June 30, 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 June 30, 2005, $3.6 billion had been expended to repurchase 69,721,000 shares since the common stock repurchase program began.


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

The following matters were submitted to a vote of stockholders at the Annual Meeting on April 27, 2005. Voters elected twelve directors for one-year terms. The vote tabulation for individual directors was:


Directors	Shares For		Shares Withheld

Samuel H. Armacost		1,801,541,707		54,461,676
Robert E. Denham		1,756,743,039		99,260,345
Robert J. Eaton		1,806,879,155		49,124,228
Sam L. Ginn		1,796,335,842		59,667,541
Carla A. Hills		1,795,866,226		60,137,157
Franklyn G. Jenifer		1,805,802,898		50,200,486
Sam Nunn		1,802,733,133		53,270,250
David J. O’Reilly		1,806,813,543		49,189,841
Peter J. Robertson		1,808,135,313		47,868,070
Charles R. Shoemate		1,821,480,745		34,522,639
Ronald D. Sugar		1,822,340,229		33,663,154
Carl Ware		1,821,953,365		34,050,018

Concerning Ratification of Independent Registered Public Accounting Firm


Votes Cast For:			1,798,664,282
Votes Cast Against:			41,433,105
Abstentions:			15,905,718
Broker Non-Votes:			N/A

Concerning Stockholder Proposal on Directors’ Compensation


Votes Cast For:			101,771,905
Votes Cast Against:			1,392,469,720
Abstentions:			28,528,509
Broker Non-Votes:			333,233,249

Concerning Stockholder Proposal on Executive Severance Agreements


Votes Cast For:			824,614,963
Votes Cast Against:			645,467,546
Abstentions:			52,643,693
Broker Non-Votes:			333,277,181

Concerning Stockholder Proposal on Stock Option Expensing


Votes Cast For:			866,823,905
Votes Cast Against:			607,949,146
Abstentions:			47,954,076
Broker Non-Votes:			333,276,256

Concerning Stockholder Proposal on Use of Animal Testing


Votes Cast For:			46,344,152
Votes Cast Against:			1,304,911,383
Abstentions:			171,517,294
Broker Non-Votes:			333,230,554

Concerning Stockholder Proposal on Drilling in Sensitive and Protected Areas


Votes Cast For:			116,737,586
Votes Cast Against:			1,233,336,701
Abstentions:			172,695,415
Broker Non-Votes:			333,233,681

Concerning Stockholder Proposal to Report on Ecuador


Votes Cast For:			124,040,489
Votes Cast Against:			1,225,009,455
Abstentions:			173,722,571
Broker Non-Votes:			333,230,868


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 by executive officers or directors for the period that ended on June 30, 2005.


Item 6.	*Exhibits*


Exhibit
Number		Description

(2.1)		Chevron Corporation and Unocal Corporation Agreement and Plan of Merger, dated April 4, 2005, filed as Exhibit 2.1 to Chevron’s Current Report on Form 8-K dated April 7, 2005, and incorporated herein by reference.
(2.2)		Chevron Corporation and Unocal Corporation Amendment No. 1 to Agreement and Plan of Merger, dated July 19, 2005, filed as Annex A to Exhibit 20.1 to Chevron’s Current Report on Form 8-K dated July 25, 2005, and incorporated herein by reference.
(3.1)		Restated Certificate of Incorporation dated May 9, 2005, filed as Exhibit 99.1 to Chevron’s Current Report on Form 8-K dated May 10, 2005, and incorporated herein by reference.
(3.2)		By-Laws of Chevron Corporation, as amended on June 29, 2005.
(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.
(10.16)		Form of Notice of Grant under the Chevron Corporation Long-Term Incentive Plan, filed as Exhibit 10.1 to Chevron’s Current Report on Form 8-K dated June 29, 2005, and incorporated herein by reference.
(10.17)		Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.2 to Chevron’s Current Report on Form 8-K dated June 29, 2005, and incorporated herein by reference.
(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.


		Chevron Corporation


	(Registrant)


	/s/M.A. Humphrey

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

Date: August 3, 2005

EXHIBIT INDEX


Exhibit
Number		Description

(2.1)		Chevron Corporation and Unocal Corporation Agreement and Plan of Merger, dated April 4, 2005, filed as Exhibit 2.1 to Chevron’s Current Report on Form 8-K dated April 7, 2005, and incorporated herein by reference.
(2.2)		Chevron Corporation and Unocal Corporation Amendment No. 1 to Agreement and Plan of Merger, dated July 19, 2005, filed as Annex A to Exhibit 20.1 to Chevron’s Current Report on Form 8-K dated July 25, 2005, and incorporated herein by reference.
(3.1)		Restated Certificate of Incorporation dated May 9, 2005, filed as Exhibit 99.1 to Chevron’s Current Report on Form 8-K dated May 10, 2005, and incorporated herein by reference.
(3.2)*		By-Laws of Chevron Corporation, as amended on June 29, 2005.
(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.
(10.16)		Form of Notice of Grant under the Chevron Corporation Long-Term Incentive Plan, filed as Exhibit 10.1 to Chevron’s Current Report on Form 8-K dated June 29, 2005, and incorporated herein by reference.
(10.17)		Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.2 to Chevron’s Current Report on Form 8-K dated June 29, 2005, and incorporated herein by reference.
(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, Chevron Corporation, 6001 Bollinger Canyon Road, San Ramon, California 94583.

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Chevron (CVX) 10-Q2005 Q2 Quarterly report

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