Chevron (CVX) 10-Q 2008 Q3 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 September 30, 2008
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 (Address of principal executive offices)	94583-2324 (Zip Code)

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

NONE

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o

(Do not check if a smaller

reporting company)

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Exchange Act).  Yes o     No þ

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

Class	Outstanding as of September 30, 2008
Common stock, $.75 par value	2,031,790,705

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 Nine Months Ended September 30, 2008, and 2007		3
	Consolidated Statement of Comprehensive Income for the Three and Nine Months Ended September 30, 2008, and 2007		4
	Consolidated Balance Sheet at September 30, 2008, and December 31, 2007		5
	Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2008, and 2007		6
	Notes to Consolidated Financial Statements		7-21
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22-38
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		38
Item 4.	Controls and Procedures		38
PART II OTHER INFORMATION
Item 1.	Legal Proceedings		38
Item 1A.	Risk Factors		38-39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		39
Item 5.	Other Information		39
Item 6.	Exhibits		40
Signature			41
Exhibits: Computation of Ratio of Earnings to Fixed Charges			43
Rule 13a-14(a)/15d-14(a) Certifications			44-45
Section 1350 Certifications			46-47
EX-4.1
EX-4.2
EX-4.3
EX-12.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
INSTANCE DOCUMENT
SCHEMA DOCUMENT
CALCULATION LINKBASE DOCUMENT
LABELS LINKBASE DOCUMENT
PRESENTATION LINKBASE DOCUMENT
DEFINITION LINKBASE DOCUMENT

1

CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This quarterly report onForm 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,” “budgets” 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 theseforward-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 important factors that could cause actual results to differ materially from those in theforward-looking statements are crude-oil and natural-gas prices; refining, marketing and chemicals margins; actions of competitors; timing of exploration expenses; the competitiveness of alternate energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude-oil and natural-gas development projects; potential delays in the development, construction orstart-up of planned projects; the potential disruption or interruption of the company’s net production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or crude-oil production quotas that might be imposed by OPEC (Organization of Petroleum Exporting Countries); the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; the potential liability resulting from pending or future litigation; the company’s acquisition or disposition of assets; gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; 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” on pages 32 and 33 of the company’s 2007 Annual Report onForm 10-K/A. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

2

PART I.

FINANCIAL INFORMATION

Item 1.   Consolidated Financial Statements

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF INCOME

(Unaudited)

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars, except per-share amounts)
Revenues and Other Income
Sales and other operating revenues*	$	76,192	$	53,545	$	221,813	$	154,191
Income from equity affiliates		1,673		1,160		4,480		2,991
Other income		1,002		468		1,509		2,312
Total Revenues and Other Income		78,867		55,173		227,802		159,494
Costs and Other Deductions
Purchased crude oil and products		49,238		33,988		147,822		95,253
Operating expenses		5,676		4,397		15,379		12,134
Selling, general and administrative expenses		1,278		1,446		4,264		4,093
Exploration expenses		271		295		831		874
Depreciation, depletion and amortization		2,449		2,495		6,939		6,614
Taxes other than on income*		5,614		5,538		16,756		16,706
Interest and debt expense		—		22		—		159
Minority interests		32		25		94		72
Total Costs and Other Deductions		64,558		48,206		192,085		135,905
Income Before Income Tax Expense		14,309		6,967		35,717		23,589
Income Tax Expense		6,416		3,249		16,681		9,776
Net Income	$	7,893	$	3,718	$	19,036	$	13,813
Per Share of Common Stock:
Net Income
— Basic	$	3.88	$	1.77	$	9.29	$	6.49
— Diluted	$	3.85	$	1.75	$	9.23	$	6.45
Dividends	$	0.65	$	0.58	$	1.88	$	1.68
Weighted Average Number of Shares Outstanding (000s)
— Basic		2,032,433		2,109,345		2,049,812		2,127,409
— Diluted		2,044,616		2,124,198		2,063,149		2,141,096
* Includes excise, value-added and similar taxes:	$	2,577	$	2,550	$	7,766	$	7,573

See accompanying notes to consolidated financial statements.

3

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30						September 30
	2008			2007			2008			2007
	(Millions of dollars)
Net Income	$	7,893		$	3,718		$	19,036		$	13,813
Currency translation adjustment		(67	)		9			(84	)		12
Unrealized holding gain on securities:
Net (loss) gain arising during period		(13	)		12			(5	)		29
Derivatives:
Net derivatives loss on hedge transactions		126			—			74			(10	)
Reclassification to net income of net realized loss		4			13			15			12
Income taxes on derivatives transactions		(44	)		(4	)		(32	)		(4	)
Total		86			9			57			(2	)
Defined benefit plans:
Actuarial loss:
Amortization to net income of net actuarial loss		62			93			187			278
Actuarial gain arising during period		—			9			—			11
Prior service cost:
Amortization to net income of net prior service credits		(16	)		(5	)		(47	)		(11	)
Defined benefit plans sponsored by equity affiliates		7			5			22			13
Income taxes on defined benefit plans		(17	)		(31	)		(65	)		(98	)
Total		36			71			97			193
Other Comprehensive Gain, Net of Tax		42			101			65			232
Comprehensive Income	$	7,935		$	3,819		$	19,101		$	14,045

See accompanying notes to consolidated financial statements.

4

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

	At September 30			At December 31
	2008			2007
	(Millions of dollars, except
	per-share amounts)
ASSETS
Cash and cash equivalents	$	10,636		$	7,362
Marketable securities		347			732
Accounts and notes receivable, net		24,922			22,446
Inventories:
Crude oil and petroleum products		4,778			4,003
Chemicals		382			290
Materials, supplies and other		1,129			1,017
Total inventories		6,289			5,310
Prepaid expenses and other current assets		5,153			3,527
Total Current Assets		47,347			39,377
Long-term receivables, net		2,259			2,194
Investments and advances		21,310			20,477
Properties, plant and equipment, at cost		165,372			154,084
Less: accumulated depreciation, depletion and amortization		79,681			75,474
Properties, plant and equipment, net		85,691			78,610
Deferred charges and other assets		4,174			3,491
Goodwill		4,600			4,637
Assets held for sale		329			—
Total Assets	$	165,710		$	148,786
LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt	$	832		$	1,162
Accounts payable		22,107			21,756
Accrued liabilities		9,211			5,275
Federal and other taxes on income		5,682			3,972
Other taxes payable		1,593			1,633
Total Current Liabilities		39,425			33,798
Long-term debt		5,749			5,664
Capital lease obligations		380			406
Deferred credits and other noncurrent obligations		16,013			15,007
Noncurrent deferred income taxes		12,524			12,170
Reserves for employee benefit plans		4,454			4,449
Minority interests		211			204
Total Liabilities		78,756			71,698
Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued)		—			—
Common stock (authorized 6,000,000,000 shares, $.75 par value, 2,442,676,580 shares issued at September 30, 2008, and December 31, 2007)		1,832			1,832
Capital in excess of par value		14,415			14,289
Retained earnings		97,507			82,329
Notes receivable — key employees		(1	)		(1	)
Accumulated other comprehensive loss		(1,950	)		(2,015	)
Deferred compensation and benefit plan trust		(434	)		(454	)
Treasury stock, at cost (410,885,875 and 352,242,618 shares at September 30, 2008, and December 31, 2007, respectively)		(24,415	)		(18,892	)
Total Stockholders’ Equity		86,954			77,088
Total Liabilities and Stockholders’ Equity	$	165,710		$	148,786

See accompanying notes to consolidated financial statements.

5

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30
	2008			2007
	(Millions of dollars)
Operating Activities
Net income	$	19,036		$	13,813
Adjustments
Depreciation, depletion and amortization		6,939			6,614
Dry hole expense		287			324
Distributions less than income from equity affiliates		(278	)		(1,070	)
Net before-tax gains on asset retirements and sales		(757	)		(2,099	)
Net foreign currency effects		(74	)		299
Deferred income tax provision		37			105
Net increase in operating working capital		(713	)		(729	)
Minority interest in net income		94			72
Increase in long-term receivables		(221	)		(75	)
Increase in other deferred charges		(70	)		(134	)
Cash contributions to employee pension plans		(169	)		(219	)
Other		313			993
Net Cash Provided by Operating Activities		24,424			17,894
Investing Activities
Capital expenditures		(13,632	)		(11,381	)
Proceeds from asset sales		1,384			3,016
Net sales of marketable securities		351			123
Repayment of loans by equity affiliates		169			11
Proceeds from sale of other short-term investments		359			—
Net Cash Used for Investing Activities		(11,369	)		(8,231	)
Financing Activities
Net borrowings (payments) of short-term obligations		661			(1,004	)
Repayments of long-term debt and other financing obligations		(926	)		(3,221	)
Cash dividends		(3,861	)		(3,577	)
Dividends paid to minority interests		(88	)		(58	)
Net purchases of treasury shares		(5,530	)		(4,442	)
Net Cash Used for Financing Activities		(9,744	)		(12,302	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		(37	)		96
Net Change in Cash and Cash Equivalents		3,274			(2,543	)
Cash and Cash Equivalents at January 1		7,362			10,493
Cash and Cash Equivalents at September 30	$	10,636		$	7,950

See accompanying notes to consolidated financial statements.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.   Interim Financial Statements

The accompanying consolidated financial statements of Chevron Corporation and its subsidiaries (the company) have not been audited by an independent registered public accounting firm. 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.

Certain notes and other information have been condensed or omitted from the interim financial statements presented in this Quarterly Report onForm 10-Q. Therefore, these financial statements should be read in conjunction with the company’s 2007 Annual Report onForm 10-K/A.

The results for the three- and nine-month periods ended September 30, 2008, are not necessarily indicative of future financial results.

Earnings for the third quarter 2008 included approximately $400 million of expenses associated with damage to upstream facilities in the U.S. Gulf of Mexico caused by hurricanes Gustav and Ike. Largely offsetting the impact of these expenses were gains of about $350 million on U.S. upstream asset sales.

Earnings for the third quarter 2007 included a $265 million gain on the sale of marketing assets in the Benelux region of Europe. Earnings for the first nine months of 2007 also included a $700 million gain on a sale of the company’s interest in refining and related assets in the Netherlands and a $680 million gain on the sale of the company’s holding of Dynegy Inc. common stock.

Note 2.   Information Relating to the Consolidated Statement of Cash Flows

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

	Nine Months Ended
	September 30
	2008			2007
	(Millions of dollars)
Increase in accounts and notes receivable	$	(2,559	)	$	(1,665	)
Increase in inventories		(979	)		(1,099	)
Increase in prepaid expenses and other current assets		(461	)		(332	)
Increase in accounts payable and accrued liabilities		1,507			2,638
Increase (decrease) in income and other taxes payable		1,779			(271	)
Net increase in operating working capital	$	(713	)	$	(729	)

The table above excludes items that did not affect cash. The “Increase in accounts payable and accrued liabilities” for the nine months ended September 30, 2008, excludes a $2 billion increase in “Accrued liabilities” for a noncash item that was offset to “Properties, plant and equipment” on the Consolidated Balance Sheet. This was the most significant noncash item and relates to an accrual associated with an upstream operating agreement outside the United States.

In accordance with the cash-flow classification requirements of FAS 123R,Share-Based Payment,the “Net increase in operating working capital” includes reductions of $102 million and $90 million for excess income tax benefits associated with stock options exercised during the nine months ended September 30, 2008, and 2007, respectively. These amounts are offset by an equal amount in “Net purchases of treasury shares.”

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	Nine Months Ended
	September 30
	2008		2007
	(Millions of dollars)
Interest on debt (net of capitalized interest)	$	—	$	193
Income taxes		14,298		9,684

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

	Nine Months Ended
	September 30
	2008			2007
	(Millions of dollars)
Marketable securities purchased	$	(3,232	)	$	(904	)
Marketable securities sold		3,583			1,027
Net sales of marketable securities	$	351		$	123

The “Net purchases of treasury shares” represents the cost of common shares less the cost of shares issued for share-based compensation plans. Net purchases totaled $5.5 billion and $4.4 billion in the 2008 and 2007 periods, respectively. Purchases in the first nine months of 2008 were under the company’s stock repurchase program initiated in September 2007. Purchases in the first nine months of 2007 were primarily under the company’s stock buyback program initiated in December 2006 and completed in September 2007.

The major components of “Capital expenditures” and the reconciliation of this amount to the capital and exploratory expenditures, including equity affiliates are presented in the following table:

	Nine Months Ended
	September 30
	2008			2007
	(Millions of dollars)
Additions to properties, plant and equipment*	$	12,812		$	10,633
Additions to investments		715			619
Current-year dry-hole expenditures		239			264
Payments for other liabilities and assets, net		(134	)		(135	)
Capital expenditures		13,632			11,381
Expensed exploration expenditures		544			550
Assets acquired through capital-lease obligations		14			193
Capital and exploratory expenditures, excluding equity affiliates		14,190			12,124
Company’s share of expenditures by equity affiliates		1,587			1,659
Capital and exploratory expenditures, including equity affiliates	$	15,777		$	13,783

* Excludes $2 billion noncash addition discussed on page 7.

Note 3.   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”

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

as defined in Financial Accounting Standards Board (FASB) Statement No. 131,Disclosures about Segments of an Enterprise and Related Information(FAS 131).

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 that 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, which makes decisions about resources to be allocated to the segments and to assess their performance; and (c) for which discrete financial information is available.

Segment managers for the reportable segments are directly accountable to and maintain regular contact with the company’s CODM to discuss the segment’s operating activities and financial performance. The CODM approves annual capital and exploratory budgets at the reportable segment level, as well as 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 in other committees for purposes other than acting as the CODM.

“All other” activities include mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, alternative fuels, technology companies, and the company’s interest in Dynegy Inc. prior to its sale in May 2007.

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).

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Segment Income  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 by major operating area for the three- and nine-month periods ended September 30, 2008 and 2007, is presented in the following table:

Segment Income

	Three Months Ended						Nine Months Ended
	September 30						September 30
	2008			2007			2008			2007
	(Millions of dollars)
Upstream
United States	$	2,187		$	1,135		$	5,977		$	3,154
International		3,995			2,296			12,581			6,823
Total Upstream		6,182			3,431			18,558			9,977
Downstream
United States		1,014			(110	)		336			1,021
International		817			487			1,013			2,277
Total Downstream		1,831			377			1,349			3,298
Chemicals
United States		30			70			32			209
International		40			33			122			118
Total Chemicals		70			103			154			327
Total Segment Income		8,083			3,911			20,061			13,602
All Other
Interest Expense		—			(15	)		—			(103	)
Interest Income		52			114			157			327
Other		(242	)		(292	)		(1,182	)		(13	)
Net Income	$	7,893		$	3,718		$	19,036		$	13,813

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Segment Assets  Segment assets do not include intercompany investments or intercompany receivables. “All Other” assets in 2008 consist primarily of worldwide cash, cash equivalents and marketable securities, real estate, information systems, mining operations, power generation businesses, technology companies and assets of the corporate administrative functions. Segment assets at September 30, 2008, and December 31, 2007, are as follows:

Segment Assets

	At September 30		At December 31
	2008		2007
	(Millions of dollars)
Upstream
United States	$	24,862	$	23,535
International		70,359		61,049
Goodwill		4,600		4,637
Total Upstream		99,821		89,221
Downstream
United States		17,921		16,790
International		28,215		26,075
Total Downstream		46,136		42,865
Chemicals
United States		2,620		2,484
International		1,021		870
Total Chemicals		3,641		3,354
Total Segment Assets		149,598		135,440
All Other
United States		8,648		6,847
International		7,464		6,499
Total All Other		16,112		13,346
Total Assets — United States		54,051		49,656
Total Assets — International		107,059		94,493
Goodwill		4,600		4,637
Total Assets	$	165,710	$	148,786

Segment Sales and Other Operating Revenues  Operating-segment sales and other operating revenues, including internal transfers, for the three- and nine-month periods ended September 30, 2008, and 2007, are presented in the following table. Products are transferred between operating segments at internal product values that approximate market prices. Revenues for the upstream segment are derived primarily from the production and sale 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, 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 fuels. “All Other” activities include revenues from mining operations, power generation businesses, insurance operations, real estate activities and technology companies.

11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Sales and Other Operating Revenues

	Three Months Ended						Nine Months Ended
	September 30						September 30
	2008			2007			2008			2007
	(Millions of dollars)
Upstream
United States	$	11,036		$	7,252		$	32,980		$	22,347
International		12,295			8,297			36,514			24,394
Sub-total		23,331			15,549			69,494			46,741
Intersegment Elimination — United States		(4,461	)		(3,049	)		(13,094	)		(8,036	)
Intersegment Elimination — International		(6,840	)		(4,828	)		(21,009	)		(13,743	)
Total Upstream		12,030			7,672			35,391			24,962
Downstream
United States		27,692			19,611			77,803			54,561
International		35,924			25,750			107,086			73,294
Sub-total		63,616			45,361			184,889			127,855
Intersegment Elimination — United States		(126	)		(110	)		(377	)		(377	)
Intersegment Elimination — International		(44	)		(1	)		(107	)		(16	)
Total Downstream		63,446			45,250			184,405			127,462
Chemicals
United States		146			135			424			458
International		443			361			1,265			1,018
Sub-total		589			496			1,689			1,476
Intersegment Elimination — United States		(60	)		(61	)		(189	)		(179	)
Intersegment Elimination — International		(43	)		(38	)		(122	)		(118	)
Total Chemicals		486			397			1,378			1,179
All Other
United States		448			393			1,212			1,036
International		19			21			56			59
Sub-total		467			414			1,268			1,095
Intersegment Elimination — United States		(230	)		(181	)		(611	)		(491	)
Intersegment Elimination — International		(7	)		(7	)		(18	)		(16	)
Total All Other		230			226			639			588
Sales and Other Operating Revenues
United States		39,322			27,391			112,419			78,402
International		48,681			34,429			144,921			98,765
Sub-total		88,003			61,820			257,340			177,167
Intersegment Elimination — United States		(4,877	)		(3,401	)		(14,271	)		(9,083	)
Intersegment Elimination — International		(6,934	)		(4,874	)		(21,256	)		(13,893	)
Total Sales and Other Operating Revenues	$	76,192		$	53,545		$	221,813		$	154,191

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4.   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, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method.

During the third quarter of 2008, Chevron implemented legal reorganizations in which certain Chevron subsidiaries transferred assets to or under CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the table below gives retroactive effect to the reorganization as if it had occurred on January 1, 2007. However, the final information below may not reflect the financial position and operating results in the future or the historical results in the period presented if the reorganization actually had occurred on that date.

The summarized financial information for CUSA and its consolidated subsidiaries is presented in the table below:

	Nine Months Ended
	September 30
	2008		2007
	(Millions of dollars)
Sales and other operating revenues	$	166,627	$	109,822
Costs and other deductions		159,855		104,961
Net income		4,555		4,308

	At September 30		At December 31
	2008		2007
	(Millions of dollars)
Current assets	$	37,781	$	32,801
Other assets		30,443		27,401
Current liabilities		23,001		20,050
Other liabilities		11,933		11,447
Net equity	$	33,290	$	28,705
Memo: Total debt	$	4,253	$	4,433

Note 5.   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 fully and unconditionally 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 September 30					Nine Months Ended September 30
	2008		2007			2008		2007
	(Millions of dollars)
Sales and other operating revenues	$	294	$	157		$	795	$	496
Costs and other deductions		269		183			722		514
Net income (loss)		25		(25	)		115		(14	)

13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	At September 30		At December 31
	2008		2007
	(Millions of dollars)
Current assets	$	519	$	335
Other assets		173		337
Current liabilities		136		107
Other liabilities		86		188
Net equity	$	470	$	377

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at September 30, 2008.

Note 6.   Income Taxes

Taxes on income for the third quarter and first nine months of 2008 were $6.4 billion and $16.7 billion, respectively, compared with $3.2 billion and $9.8 billion for the corresponding periods in 2007. The associated effective tax rates for the third quarters of 2008 and 2007 were 45 percent and 47 percent, respectively. The lower rate for the 2008 third quarter was associated with a greater proportion of income being earned in tax jurisdictions with lower tax rates. For the comparative nine-month periods, the effective tax rates were 47 percent and 41 percent, respectively. The higher rate for the 2008 period was primarily associated with a greater proportion of income being earned in tax jurisdictions with higher income tax rates. In addition, the 2007 nine-month period included a relatively low effective tax rate on the sale of the company’s investment in Dynegy common stock and the sale of refining-related assets in the Netherlands.

Note 7.   Employee Benefits

The company has defined-benefit pension plans for many employees. The company typically prefunds defined-benefit plans as required by local regulations or in certain situations where pre-funding provides economic advantages. In the United States, this includes all qualified plans subject to the Employee Retirement Income Security Act of 1974 (ERISA) minimum funding standard. The company does not typically fund U.S. nonqualified pension plans that are not subject to funding requirements under applicable laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.

The company also sponsors other postretirement plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and the retirees share the costs. Medical coverage for Medicare-eligible retirees in the company’s main U.S. medical plan is secondary to Medicare (including Part D) and the increase to the company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company.

14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The components of net periodic benefit costs for 2008 and 2007 were:

	Three Months Ended						Nine Months Ended
	September 30						September 30
	2008			2007			2008			2007
	(Millions of dollars)
Pension Benefits
United States
Service cost	$	63		$	65		$	188		$	195
Interest cost		125			120			374			362
Expected return on plan assets		(149	)		(144	)		(445	)		(433	)
Amortization of prior-service costs		(1	)		11			(5	)		34
Amortization of actuarial losses		14			32			44			96
Settlement losses		19			20			58			61
Total United States		71			104			214			315
International
Service cost		34			30			102			92
Interest cost		81			60			224			187
Expected return on plan assets		(76	)		(62	)		(209	)		(192	)
Amortization of prior-service costs		6			5			19			13
Amortization of actuarial losses		19			20			56			60
Curtailment losses		—			—			—			3
Termination costs		—			—			1			—
Total International		64			53			193			163
Net Periodic Pension Benefit Costs	$	135		$	157		$	407		$	478
Other Benefits*
Service cost	$	7		$	8		$	63		$	40
Interest cost		45			46			134			138
Amortization of prior-service costs		(21	)		(21	)		(61	)		(61	)
Amortization of actuarial losses		10			21			29			61
Net Periodic Other Benefit Costs	$	41		$	54		$	165		$	178

* 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 2007, the company estimated it would contribute $500 million to employee pension plans during 2008 (composed of $300 million for the U.S. plans and $200 million for the international plans). Through September 30, 2008, a total of $169 million was contributed (including $71 million to the U.S. plans). Total estimated contributions for the full year continue to be $500 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 nine months of 2008, the company contributed $144 million to its other postretirement benefit plans. The company anticipates contributing $63 million during the remainder of 2008.

15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8.   Accounting for Suspended Exploratory Wells

The company accounts for the cost of exploratory wells in accordance with FAS 19,Financial Accounting and Reporting by Oil and Gas Producing Companies,as amended by FASB Staff PositionFAS 19-1,Accounting for Suspended Well Costs, which provides that an exploratory well continues to be capitalized after the completion of drilling if certain criteria are met. The company’s capitalized cost of suspended wells at September 30, 2008, was $1.93 billion, an increase of approximately $270 million from year-end 2007 due to drilling activities in Australia, the United States and Nigeria. For the category of exploratory well costs at year-end 2007 that were suspended more than one year, a total of $66 million was expensed in the first nine months of 2008.

Note 9.   Litigation

MTBE  Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. In October 2008, 59 cases were settled in which the company was a party and which related to the use of MTBE in certain oxygenated gasolines and the alleged seepage of MTBE into groundwater. The terms of this agreement are confidential and not material to the company’s results of operations, liquidity or financial position.

Chevron is a party to 32 other pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims 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 settlement of the 59 lawsuits did not set any precedents related to standards of liability to be used to judge the merits of the claims, corrective measures required or monetary damages to be assessed for the remaining lawsuits and claims or future lawsuits and claims. As a result, the company’s ultimate exposure related to pending lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company no longer uses MTBE in the manufacture of gasoline in the United States.

RFG Patent  Fourteen purported class actions were brought by consumers who purchased reformulated gasoline (RFG) from January 1995 through August 2005, alleging that Unocal misled the California Air Resources Board into adopting standards for composition of RFG that overlapped with Unocal’s undisclosed and pending patents. The parties have finalized settlement of all these matters. On August 14, 2008, the United States District Court for the Central District of California granted plaintiffs’ motion for preliminary approval of aclass-action settlement. The settlement calls for, among other things, Unocal to pay $48 million, and for the establishment of acy presfund to administer payout of the award. Plaintiffs’ motion for the court’s final approval is scheduled for November 24, 2008.

Ecuador  Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations, and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium, and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpet’s ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40 million. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations.

Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which

16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

plaintiffs bring the action, enacted in 1999, cannot be applied retroactively to Chevron; third, that the claims are barred by the statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador. With regard to the facts, the Company believes that the evidence confirms that Texpet’s remediation was properly conducted and that the remaining environmental damage reflects Petroecuador’s failure to timely fulfill its legal obligations and Petroecuador’s further conduct since assuming full control over the operations.

In April 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $8 billion, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, healthcare systems, and additional infrastructure for Petroecuador. The engineer’s report also asserts that an additional $8.3 billion could be assessed against Chevron for unjust enrichment. The engineer’s report is not binding on the court. Chevron also believes that the engineer’s work was performed, and his report prepared, in a manner contrary to law and in violation of the court’s orders. Chevron has submitted a rebuttal to the report in which it asks the court to strike the report in its entirety, and Chevron will continue a vigorous defense of any attempted imposition of liability.

Management does not believe an estimate of a reasonably possible loss (or a range of loss) can be made in this case. Due to the defects associated with the engineer’s report, management does not believe the report itself has any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to estimate a reasonably possible loss (or a range of loss).

Note 10.   Other Contingencies and Commitments

Guarantees  The company and its subsidiaries have certain other contingent liabilities with respect to guarantees, direct or indirect, of debt of affiliated companies or third parties. 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 may have recourse provisions that would enable the company to recover any payments made under the terms of the guarantees from assets provided as collateral.

Off-Balance-Sheet Obligations  The company and its subsidiaries have certain other contractual obligations relating to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline, storage and regasification capacity, drilling rigs, utilities and petroleum products, to be used or sold in the ordinary course of the company’s business.

Indemnifications  The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. The company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make future payments up to $300 million. Through the end of September 2008, the company paid $48 million under these indemnities and continues to be obligated for possible additional 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 interest 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 must be asserted no later than February 2009 for Equilon indemnities and no later than February 2012 for Motiva indemnities. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments. The company has not recorded any liabilities for possible claims under these indemnities. The company posts no assets as collateral and has made no payments under the indemnities.

17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. Under the indemnification agreement, the company’s liability is unlimited until April 2022, when the liability expires. The acquirer of the assets sold in 1997 shares in certain environmental remediation costs up to a maximum obligation of $200 million, which had not been reached as of September 30, 2008.

Securitization  During the third quarter 2008, the company terminated the program used to securitize downstream-related trade accounts receivable. At year-end 2007, the balance of securitized receivables was $675 million. As of September 30, 2008, the company had no other securitization arrangements in place.

Minority Interests  The company has commitments of $211 million related to minority interests in subsidiary companies.

Environmental  The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals 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, land development areas, and mining operations, 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 chemical companies.

Chevron’s environmental reserve at December 31, 2007, was approximately $1.5 billion. At September 30, 2008, the environmental reserve was approximately $1.9 billion. The increase was mainly associated with remediation liabilities Chevron has incurred for sites that were previously sold.

Financial Instruments  The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodities and other derivatives activities, including forward-exchange contracts and interest rate swaps.

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, 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. For this range of settlement, Chevron estimates its maximum possible net before-tax liability at approximately $200 million, and the possible maximum net amount that could be owed to Chevron is estimated at about $150 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

Note 11.   Restructuring and Reorganization Costs

In 2007, the company implemented a restructuring and reorganization program in its global downstream operations. Approximately 1,000 employees were eligible for severance payments. As of September 30, 2008, approximately 600 employees had been terminated under the program. Most of the associated positions are located outside of the United States. The program is expected to be complete by the end of 2009.

Shown in the table below is the activity for the company’s liability related to the downstream reorganization. The associated charges against income were categorized as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income.

	Amounts Before Tax
	(Millions of dollars)
Balance at January 1, 2008	$	85
Accruals/Adjustments		(5	)
Payments		(48	)
Balance at September 30, 2008	$	32

Note 12.   Fair Value Measurements

The company implemented FASB Statement No. 157,Fair Value Measurements(FAS 157), as of January 1, 2008. FAS 157 was amended in February 2008 by FASB Staff Position (FSP)FAS No. 157-1,Application of FASB Statement No. 157 to FASB Statement No. 13 and Its Related Interpretive Accounting Pronouncements That Address Leasing Transactions,and by FSPFAS 157-2,Effective Date of FASB Statement No. 157, which delayed the company’s application of FAS 157 for nonrecurring nonfinancial assets and liabilities until January 1, 2009. FAS 157 was further amended in October 2008 by FSPFAS 157-3,Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,which clarifies the application of FAS 157 to assets participating in inactive markets.

Implementation of FAS 157 did not have a material effect on the company’s results of operations or consolidated financial position and had no effect on the company’s existing fair-value measurement practices. However, FAS 157 requires disclosure of a fair-value hierarchy of inputs the company uses to value an asset or a liability. The three levels of the fair-value hierarchy are described as follows:

Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities. For the company, Level 1 inputs include exchange-traded futures contracts for which the parties are willing to transact at the exchange-quoted price and marketable securities that are actively traded.

Level 2: Inputs other than Level 1 that are observable, either directly or indirectly. For the company, Level 2 inputs include quoted prices for similar assets or liabilities, prices obtained through third-party broker quotes and prices that can be corroborated with other observable inputs for substantially the complete term of a contract.

Level 3: Unobservable inputs. The company does not use Level 3 inputs for any of its recurring fair-value measurements. Beginning January 1, 2009, Level 3 inputs may be required for the determination of fair value associated with certain nonrecurring measurements of nonfinancial assets and liabilities.

19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The fair value hierarchy for assets and liabilities measured at fair value at September 30, 2008, is as follows:

Assets and Liabilities Measured at Fair Value on a Recurring Basis

			Prices in Active		Other
			Markets for		Observable		Unobservable
	At September 30		Identical Assets		Inputs		Inputs
	2008		(Level 1)		(Level 2)		(Level 3)
Marketable Securities	$	347	$	347	$	—	$	—
Derivatives		561		315		246	$	—
Total Assets at Fair Value	$	908	$	662	$	246	$	—
Derivatives	$	556	$	66	$	490	$	—
Total Liabilities at Fair Value	$	556	$	66	$	490	$	—

Marketable securities  The company calculates fair value for its marketable securities based on quoted market prices for identical assets and liabilities.

Derivatives  The company records its derivative instruments — other than any commodity derivative contracts that are designated as normal purchase and normal sale — on the Consolidated Balance Sheet at fair value, with virtually all the offsetting amount to the Consolidated Statement of Income. For derivatives with identical or similar provisions as contracts that are publicly traded on a regular basis, the company uses the market values of the publicly traded instruments as an input for fair-value calculations.

The company’s derivative instruments principally include crude oil, natural gas and refined-product futures, swaps, options and forward contracts, as well as interest-rate swaps and foreign-currency forward contracts. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the NYMEX (New York Mercantile Exchange).

Derivatives classified as Level 2 include swaps (including interest rate), options, and forward (including foreign currency) contracts principally with financial institutions and other oil and gas companies, the fair values for which are obtained from third party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information. The company incorporates internal review, evaluation and assessment procedures, including a comparison of Level 2 fair values derived from the company’s internally developed forward curves (on a sample basis) with the pricing information to document reasonable, logical and supportable fair-value determinations and proper Level of classification.

Note 13.   New Accounting Standards

FASB Statement No. 141 (revised 2007), Business Combinations(FAS 141-R)  In December 2007, the FASB issuedFAS 141-R, which will become effective for business combination transactions having an acquisition date on or after January 1, 2009. This standard requires the acquiring entity in a business combination to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date to be measured at their respective fair values. The statement requires acquisition-related costs, as well as restructuring costs the acquirer expects to incur for which it is not obligated at acquisition date, to be recorded against income rather than included in purchase-price determination. It also requires recognition of contingent arrangements at their acquisition-date fair values, with subsequent changes in fair value generally reflected in income.

FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (FAS 160)  The FASB issued FAS 160 in December 2007, which will become effective for the company January 1, 2009, with retroactive adoption of the Statement’s presentation and disclosure requirements for existing minority interests. This standard will require ownership interests in subsidiaries held by parties other than the parent

20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

to be presented within the equity section of the consolidated statement of financial position but separate from the parent’s equity. It will also require the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the Consolidated Statement of Income. Certain changes in a parent’s ownership interest are to be accounted for as equity transactions and when a subsidiary is deconsolidated, any noncontrolling equity investment in the former subsidiary is to be initially measured at fair value. The company does not anticipate the implementation of FAS 160 will significantly change the presentation of its Consolidated Statement of Income or Consolidated Balance Sheet.

FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities (FAS 161)  In March 2008, the FASB issued FAS 161, which becomes effective for the company on January 1, 2009. This standard amends and expands the disclosure requirements of FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities. FAS 161 requires disclosures related to objectives and strategies for using derivatives; the fair-value amounts of, and gains and losses on, derivative instruments; and credit-risk-related contingent features in derivative agreements. The effect on the company’s disclosures for derivative instruments as a result of the adoption of FAS 161 in 2009 will depend on the company’s derivative instruments and hedging activities at that time.

21

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

Third Quarter 2008 Compared with Third Quarter 2007
and Nine Months 2008 Compared with Nine Months 2007

Key Financial Results

Income by Business Segment

	Three Months Ended						Nine Months Ended
	September 30						September 30
	2008			2007			2008			2007
	(Millions of dollars)
Upstream — Exploration and Production
United States	$	2,187		$	1,135		$	5,977		$	3,154
International		3,995			2,296			12,581			6,823
Total Upstream		6,182			3,431			18,558			9,977
Downstream — Refining, Marketing and Transportation
United States		1,014			(110	)		336			1,021
International		817			487			1,013			2,277
Total Downstream		1,831			377			1,349			3,298
Chemicals		70			103			154			327
Total Segment Income		8,083			3,911			20,061			13,602
All Other		(190	)		(193	)		(1,025	)		211
Net Income*	$	7,893		$	3,718		$	19,036		$	13,813
* Includes foreign currency effects	$	303		$	(92	)	$	384		$	(350	)

Net incomefor the third quarter 2008 was $7.9 billion ($3.85 per share — diluted), compared with $3.7 billion ($1.75 per share — diluted) in the corresponding 2007 period. Net income for the first nine months of 2008 was $19.0 billion ($9.23 per share — diluted), versus $13.8 billion ($6.45 per share — diluted) in the 2007 first nine months. In the following discussion, the term “earnings” is defined as segment income.

Upstreamearnings in the third quarter of 2008 were $6.2 billion, compared with $3.4 billion in the year-ago period. Earnings for the first nine months of 2008 were $18.6 billion, versus $10.0 billion a year earlier. The increase for both comparative periods was driven by higher prices for crude oil and natural gas.

Downstreamearnings in the third quarter 2008 of $1.8 billion increased from $377 million a year earlier due to improved margins on the sale of refined products. The 2007 quarter included a $265 million gain on the sale of marketing assets in Europe.

Nine-month 2008 profits were $1.3 billion, down from $3.3 billion in the corresponding 2007 period. Downstream operated at a loss for the first six months of 2008 due to market conditions that prevented escalating costs of crude-oil feedstocks used in the refining process from being fully recovered in the sales price of refined products. Besides the referenced $265 million gain in the 2007 third quarter, the first nine months of 2007 also included a $700 million gain on the sale of the company’s interest in a refinery and related assets in the Netherlands.

Chemicalsearned $70 million and $154 million for the third quarter and first-nine months of 2008, respectively. Comparative amounts in 2007 were $103 million and $327 million.

Refer to pages 26 to 29 for additional discussion of earnings by business segment and “All Other” activities for the third quarter and first nine months of 2008 versus the same periods in 2007.

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Business Environment and Outlook

Chevron is a global energy company with its most significant business activities in the following countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Cambodia, Canada, Chad, China, Colombia, Democratic Republic of the Congo, Denmark, France, India, Indonesia, Kazakhstan, Myanmar, the Netherlands, Nigeria, Norway, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, the Philippines, Qatar, Republic of the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, Venezuela and Vietnam.

Chevron’s current and future earnings depend largely on the profitability of its upstream (exploration and production) and downstream (refining, marketing and transportation) business segments. The single biggest factor that affects the results of operations for both segments is movement in the price of crude oil. In the downstream business, crude oil is the largest cost component of refined products. The overall trend in earnings is typically less affected by results from the company’s chemicals business and other activities and investments. Earnings for the company in any period may also be influenced by events or transactions that are infrequentand/or unusual in nature.

Chevron and the oil and gas industry at large continue to experience an increase in certain costs that exceeds the general trend of inflation in many areas of the world. This increase in costs is affecting the company’s operating expenses for all business segments and capital expenditures, but particularly for the upstream business. The company’s operations, particularly upstream, can also be affected by changing economic, regulatory and political environments in the various countries in which it operates, including the United States. Civil unrest, acts of violence or strained relations between a government and the company or other governments may impact the company’s operations or investments. 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.

To sustain its long-term competitive position in the upstream business, the company must develop and replenish an inventory of projects that offer adequate financial returns for the investment required. Identifying promising areas for exploration, acquiring the necessary rights to explore for and to produce crude oil and natural gas, drilling successfully, and handling the many technical and operational details in a safe and cost-effective manner, are all important factors in this effort. Projects often require long lead times and large capital commitments. In the current environment of higher commodity prices, certain governments have sought to renegotiate contracts or impose additional costs and taxes on the company. Other governments may attempt to do so in the future. The company will continue to monitor these developments, take them into account in evaluating future investment opportunities, and otherwise seek to mitigate any risks to the company’s current operations or future prospects.

The company also continually evaluates opportunities to dispose of assets that are not key to providing sufficient long-term value, or to acquire assets or operations complementary to its asset base to help augment the company’s growth. In October 2008, the company received 14.2 million shares of its common stock in exchange for Chevron’s 44 percent interest in Drunkard’s Wash coalbed natural-gas field in Utah plus $280 million cash. The company expects to record a significant gain on the transaction in the fourth quarter 2008. Asset dispositions and restructurings may occur in future periods and could result in significant gains or losses.

The company has been closely monitoring the ongoing uncertainty in financial and credit markets, the recent rapid decline in crude-oil prices, and the signs of a general contraction of worldwide economic activity. Management is taking these developments into account in the conduct of daily operations and for business planning. The company remains confident of its underlying financial strength to deal with potential problems presented by this environment.

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

Upstream  Earnings for the upstream segment are closely aligned 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 damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Moreover, any of these factors could also inhibit the company’s production

23

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.

Price levels for capital and exploratory costs and operating expenses associated with the efficient production of crude-oil and natural-gas can also be subject to external factors beyond the company’s control. External factors include not only the general level of inflation but also prices charged by the industry’s material- andservice-providers, which can be affected by the volatility of the industry’s own supply and demand conditions for such materials and services. The oil and gas industry worldwide has experienced significant price increases for these items since 2005, and future price increases may continue to exceed the general level of inflation. Capital and exploratory expenditures and operating expenses also can be affected by damages to production facilities caused by severe weather or civil unrest.

As shown in the chart at left, the industry price for West Texas Intermediate (WTI), a benchmark crude oil, started 2007 at about $60 per barrel and ended the year at $96. The average price for the year was $72.

In 2008, WTI peaked above $145 per barrel in early July and fell sharply to about $100 by the end of the third quarter. The average price for the first nine months of 2008 was $114 per barrel. By the end of October, the WTI price had fallen to about $68.

Until the drop in crude-oil prices that began in mid-2008, worldwide prices had remained strong due mainly to increasing demand in growing economies, the heightened level of geopolitical uncertainty in some areas of the world and supply concerns in other key producing regions. The recent slowdown in world economic growth has contributed to a decline in oil demand and the associated drop in prices.

As in 2007, a wide differential in prices existed during the first nine months of 2008 between high-quality (high-gravity, low sulfur) crude oils and those of lower quality (low-gravity, high sulfur). The relatively lower price for the heavier crudes has been associated with an ample supply and a relatively lower demand due to the limited number of refineries that are able to process this lower-quality feedstock into light products (motor gasoline, jet fuel, aviation gasoline and diesel fuel). Chevron produces or shares in the production of heavy crude oil in California, Chad, Indonesia, the Partitioned Neutral Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom North Sea. (Refer to page 32 for the company’s average U.S. and international crude-oil realizations.)

In contrast to price movements in the global market for crude oil, price changes for natural gas in many regional markets are more closely aligned with supply and demand conditions in those markets. As indicated in the chart at the top of the page, U.S. benchmark prices at Henry Hub averaged nearly $10 per thousand cubic feet (MCF) in the first nine months of 2008, compared with $7 for the first nine months and for the full year 2007. At the end of October 2008, the Henry Hub spot price was $6.78 per MCF. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the level of inventory in underground storage relative to customer demand.

Certain other regions of the world in which the company operates have different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices for the company’s production of natural gas. (Refer to page 32 for the company’s average natural gas realizations 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 to transport and receive liquefied natural gas.

To help address this regional imbalance between supply and demand for natural gas, Chevron is planning increased investments in long-term projects in areas of excess supply to install infrastructure to produce and liquefy natural

24

gas for transport by tanker, along with investments and commitments 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 can be transported in existing natural gas pipeline networks (as in the United States).

Besides the impact of the fluctuation in prices for crude oil and natural gas, the longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, changes in tax rates on income, and the cost of goods and services.

In the first nine months of 2008, the company’s worldwide oil-equivalent production averaged approximately 2.53 million barrels per day. The production outlook for 2008 and beyond is subject to many factors and uncertainties, including the impact of changing prices on volumes recoverable under certain production-sharing and variable-royalty agreements outside the United States, quotas that may be imposed by OPEC, changes in fiscal terms or restrictions on the scope of company operations, delays in projectstart-ups, and production disruptions that could be caused by severe weather, local civil unrest and changing geopolitics.

Hurricanes Gustav and Ike in the U.S. Gulf of Mexico caused a decline of approximately 150,000 barrels per day of oil-equivalent production for September 2008. At the end of October, about 90,000 barrels of dailyoil-equivalent production, or about half of the production rate in the Gulf of Mexico prior to the hurricanes, had not yet been restored. The company estimates 90 percent of the production will be restored by the fourth quarter of 2009. Less than 10,000 barrels per day are expected to be permanently shut in as a result of hurricane damage.

The outlook for future production levels also is affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. A significant majority of Chevron’s upstream investment is currently being made outside the United States. Investments in upstream projects generally begin well in advance of the start of the associated crude-oil and natural-gas production.

About one-fourth of the company’s net oil-equivalent production in the first nine months of 2008 occurred in the OPEC-member countries of Angola, Indonesia, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. On October 24, 2008, OPEC announced a reduction of 1.5 million barrels per day, or about 5 percent, from its previous production ceiling of 28.8 million barrels per day. The reduction became effective November 1, 2008. OPEC quotas did not significantly affect Chevron’s production level in 2007 or in the first nine months of 2008. The company’s current and future production levels could be affected by the OPEC limitations that became effective November 1, but any such effect is not expected to be significant.

Refer to the Results of Operations on pages 26 through 28 for additional discussion of the company’s upstream business.

Downstream  Earnings for the downstream segment are closely tied to margins on the refining and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil and feedstocks for chemical manufacturing. Industry margins are sometimes volatile and can be affected by the global and regionalsupply-and-demand balance for refined products and by changes in the price of crude oil used for refinery feedstock. Industry margins can also be influenced by refined-product inventory levels, geopolitical events, refinery maintenance programs and disruptions at refineries resulting from unplanned outages that may be due to severe weather, fires or other operational events.

Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining and marketing network, the effectiveness of the crude-oil and product-supply functions and the economic returns on invested capital. Profitability can also be affected by the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude-oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refinery and distribution network.

25

The company’s most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Latin America, Asia, sub-Saharan Africa and the United Kingdom. Chevron operates or has ownership interests in refineries in each of these areas, except Latin America. As part of its downstream strategy to focus on areas of market strength, the company recently announced plans to sell marketing businesses in several countries. Refer to the discussion in “Operating Developments” below.

Downstream earnings, especially in the United States, were weak from mid-2007 through mid-2008 due mainly to increasing prices of crude oil used in the refining process that were not always fully recovered through sales prices of refined products. Margins significantly improved in the third quarter 2008 as the price of crude oil declined.

Refer to the Results of Operations on pages 28 through 29 for additional discussion of the company’s downstream operations.

Chemicals  Earnings in the petrochemicals business are closely tied to global chemical demand, industry inventory levels and plant capacity utilization. Feedstock and fuel costs, which tend to follow crude-oil and natural-gas price movements, also influence earnings in this segment.

Refer to the Results of Operations on page 29 for additional discussion of chemical earnings.

Operating Developments

Noteworthy operating developments for the upstream business in recent months included the following:

•  Kazakhstan— Completed the second phase of a major expansion of production operations and processing facilities at the 50 percent-owned Tengizchevroil affiliate, increasing total crude-oil production capacity from 400,000 barrels per day to 540,000.

•  Nigeria— Started production offshore at the 68 percent-owned and operated Agbami Field, with total oil production averaging about 100,000 barrels per day in October and expected to achieve a total maximum of 250,000 barrels per day by the end of 2009.

•  Middle East— Signed an agreement with the Kingdom of Saudi Arabia to extend to 2039 the company’s operation of the Kingdom’s 50 percent interest in oil and gas resources of the onshore area of the Partitioned Neutral Zone between the Kingdom and the State of Kuwait.

•  Australia— Started production from Train 5 of the one-sixth-owned North West Shelf Venture onshore liquefied-natural-gas (LNG) facility in West Australia, increasing export capacity by up to 4.4 million metric tons annually to 16.3 million.

•  Canada— Finalized agreements with the government of Newfoundland and Labrador to develop the 27 percent-owned Hebron heavy-oil project off the eastern coast.

The company also recently announced plans for its downstream operations to sell marketing-related businesses in Brazil, Nigeria, Benin, Cameroon, Republic of the Congo, Côte d’Ivoire, Togo, Kenya, and Uganda.

Results of Operations

Business Segments  The following section presents the results of operations for the company’s business segments — upstream, downstream and chemicals — as well as for “all other” — the departments and companies managed at the corporate level. (Refer to Note 3 beginning on page 8 for a discussion of the company’s “reportable segments,” as defined in FAS 131,Disclosures about Segments of an Enterprise and Related Information.)

Upstream

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
U.S. Upstream Income	$	2,187	$	1,135	$	5,977	$	3,154

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U.S. upstream income of $2.2 billion in the third quarter of 2008 increased about $1 billion from the same period last year. Higher prices for crude oil and natural gas benefited earnings by about $1.25 billion between periods. The benefit of higher prices was partially offset by the impact of lower oil-equivalent production, mainly the result of production in the Gulf of Mexico that was shut in or disrupted during September because of hurricanes Gustav and Ike. The 2008 quarter also included approximately $400 million of expenses associated with damage to facilities in the Gulf of Mexico caused by the hurricanes. Largely offsetting these expenses were gains of about $350 million on asset sales.

Nine-month 2008 earnings of approximately $6 billion were up $2.8 billion from the corresponding 2007 period. Higher prices for crude oil and natural gas increased earnings by $3.9 billion between periods. Partially offsetting this benefit were the impacts of lower oil-equivalent production and higher operating expenses in the 2008 period.

The average realization for crude oil and natural gas liquids in the third quarter of 2008 was about $107 per barrel, compared with $67 a year earlier. Nine-month prices per barrel were $101 and $58 for 2008 and 2007, respectively. The average natural-gas realization was $8.64 per thousand cubic feet in the 2008 quarter, compared with $5.43 in the year-ago period. Natural-gas realizations were $8.66 and $6.13 in first nine months of 2008 and 2007, respectively.

Net oil-equivalent production was 647,000 barrels per day in the third quarter 2008, down 94,000 barrels per day from a year earlier. More than half the decline was due to operations shut in or disrupted by the hurricanes. Nine-month production was 688,000 barrels per day, down 59,000 barrels per day from the first nine months of 2007. Besides the adverse impact of the hurricanes, the lower production in 2008 for both comparative periods also reflected normal field declines.

The net liquids component of oil-equivalent production decreased about 11 percent between quarters to 409,000 barrels per day. For the nine-month period, net liquids production decreased about 7 percent to 428,000 barrels per day in 2008. Net natural gas production declined about 16 percent for the quarter to 1.43 billion cubic feet per day. Between the nine-month periods, net natural gas production decreased about 9 percent to 1.56 billion cubic feet per day.

	Three Months Ended					Nine Months Ended
	September 30					September 30
	2008		2007			2008		2007
	(Millions of dollars)
International Upstream Income*	$	3,995	$	2,296		$	12,581	$	6,823
* Includes foreign currency effects	$	316	$	(99	)	$	229	$	(329	)

International upstream income of $4 billion in the third quarter of 2008 increased $1.7 billion from a year earlier. Higher prices for crude oil and natural gas benefited earnings about $1.8 billion between periods. Partially offsetting the benefit of higher prices were a reduction of crude-oil sales volumes due to timing of certain cargo liftings and higher operating expenses. Foreign currency effects benefited earnings by $316 million in the 2008 quarter, compared with a $99 million reduction to income a year earlier.

For the nine-month period, earnings were $12.6 billion, up about $5.8 billion from the 2007 period. Higher prices for crude oil and natural gas in 2008 increased earnings by about $6.1 billion. Partially offsetting the benefit were the same factors mentioned above for the quarterly comparison. Foreign currency effects benefited earnings by $229 million in 2008, compared with a $329 million reduction to earnings a year earlier.

The average realization for crude oil and natural gas liquids for the third quarter 2008 was about $103 per barrel, versus $67 in the 2007 period. For the first nine months of 2008, the average realization was $100 per barrel, compared with $60 for the nine months of 2007. The average natural-gas realization in the 2008 third quarter was $5.37 per thousand cubic feet, up from $3.78 in the third quarter last year. Between the nine-month periods, the average natural gas realization increased to $5.21 from $3.75.

Net oil-equivalent production, including volumes from oil sands in Canada, was 1.80 million barrels per day in the third quarter 2008, down about 3 percent from a year earlier. Production for the first nine months of 2008 was 1.84 million barrels per day, down 2 percent from the corresponding 2007 period. Absent the impact of higher prices

27

on certain production-sharing and variable-royalty agreements, net oil-equivalent production increased between both comparative periods.

The net liquids component of oil-equivalent production was 1.19 million barrels per day in the third quarter 2008 and 1.23 million barrels per day in first nine months of 2008, down 8 percent and 7 percent, respectively, from the year-ago quarters. Net natural gas production of 3.62 billion cubic feet per day in the third quarter 2008 and 3.67 billion cubic feet per day in the first nine months of 2008 increased 10 percent and 11 percent from the respective year-earlier periods.

Downstream

	Three Months Ended					Nine Months Ended
	September 30					September 30
	2008		2007			2008		2007
	(Millions of dollars)
U.S. Downstream Income (Loss)	$	1,014	$	(110	)	$	336	$	1,021

U.S. downstream earned $1 billion in the third quarter of 2008, compared with a loss of $110 million a year earlier. Approximately $800 million of the recovery in earnings was the result of higher margins on the sale of refined products and increased sales of higher-valued products. Gains on commodity derivative instruments also contributed to the increase in earnings.

Earnings for the first nine months of 2008 were $336 million, down about $700 million from the corresponding 2007 period. The decline was associated with an operating loss that occurred for the first half of 2008, when higher costs of crude-oil feedstocks used in the refining process were not fully recovered in the sales price of gasoline and other refined products. Operating expenses were also higher between the nine-months periods. Losses on commodity derivative instruments in the 2008 first half were essentially offset by gains in the third quarter.

Crude-oil inputs to the company’s refineries were 922,000 barrels per day in the third quarter of 2008, up about 15 percent from a year earlier. Between the nine-month periods, crude-oil inputs increased 9 percent. The improvement for both comparative periods was associated with less planned and unplanned refinery downtime.

Refined-product sales volumes of 1.42 million barrels per day in the 2008 third quarter were down 2 percent from the corresponding 2007 quarter. For the nine months of 2008, refined-product sales volumes of 1.41 million barrels per day were about 4 percent lower than the same period of 2007. Declines for both periods were associated with reduced sales of gasoline and fuel oil. Branded gasoline sales for the third quarter of 2008 were 601,000 barrels per day, down 7 percent from a year ago. Nine-month 2008 sales were 600,000 barrels per day, down 5 percent from the comparative 2007 period.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
International Downstream Income*	$	817	$	487	$	1,013	$	2,277
* Includes foreign currency effects	$	63	$	5	$	220	$	(25	)

International downstream income of $817 million in the 2008 third quarter increased $330 million from a year earlier. Last year’s third quarter included a $265 million gain on the sale of marketing assets in Europe. Gains on commodity derivative instruments and improved margins on the sale of refined products increased earnings about $600 million between periods. Foreign-currency effects benefited income by $63 million in the 2008 quarter, compared with $5 million a year earlier.

Earnings for the nine months of 2008 were $1 billion, down $1.3 billion from the 2007 period, which included gains of approximately $1 billion on asset sales in Europe. Also contributing to the decline were lower margins on the sale of refined products and higher operating expenses. Gains on commodity derivative instruments had a positive impact on the earnings variance between the nine-month periods. Foreign-currency effects benefited earnings by $220 million in 2008, compared with a $25 million reduction to earnings a year earlier.

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The company’s share of refinery crude-oil inputs was 976,000 barrels per day, about 6 percent lower than the third quarter of 2007 due mainly to an increase in planned and unplanned downtime at various affiliate refineries. For the nine-month period, crude-oil inputs were 965,000 barrels per day, down 5 percent due to the sale of the company’s interest in a Netherlands refinery and unplanned downtime at various refineries.

Total refined-product sales volumes of 2 million barrels per day in the 2008 quarter were 1 percent lower than last year’s corresponding period. Between the nine-month periods, refined-product sales of 2 million barrels per day increased by about 1 percent.

Chemicals

	Three Months Ended					Nine Months Ended
	September 30					September 30
	2008			2007		2008			2007
	(Millions of dollars)
Income*	$	70		$	103	$	154		$	327
* Includes foreign currency effects	$	(5	)	$	3	$	(5	)	$	2

Chemical operations earned $70 million in the third quarter 2008, compared with $103 million in the 2007 period. For the nine months, earnings decreased from $327 million in 2007 to $154 million in 2008. The lower earnings for both comparative periods were associated with narrowed margins on sales of lubricant and fuel additives by the company’s Oronite subsidiary and on sales of commodity chemicals by the 50 percent-owned Chevron Phillips Chemical Company LLC. The reduced margins reflected higher costs of feedstocks that could not be fully recovered in product sales prices. Higher utility costs for the manufacturing process and higher expenses for planned maintenance activities also contributed to the respective earnings declines.

All Other

	Three Months Ended						Nine Months Ended
	September 30						September 30
	2008			2007			2008			2007
	(Millions of dollars)
(Charges) Income — Net*	$	(190	)	$	(193	)	$	(1,025	)	$	211
* Includes foreign currency effects	$	(71	)	$	(1	)	$	(60	)	$	2

All Other includes mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, alternative fuels and technology companies, and the company’s interest in Dynegy prior to its sale in May 2007.

Net charges in the third quarter of 2008 were $190 million, compared with net charges of $193 million in the same quarter of 2007. Foreign-currency effects increased net charges by $71 million in the 2008 quarter, compared with $1 million last year. Other net charges were lower in the 2008 period.

For the nine months of 2008, net charges were approximately $1 billion, compared with income of $211 million a year earlier. The 2007 period included a gain of $680 million related to the sale of the company’s investment in Dynegy common stock, a loss of approximately $160 million associated with the early redemption of debt and net favorable tax items. Results in 2008 included net unfavorable corporate tax items and increased costs of environmental remediation for sites that previously had been closed or sold.

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Consolidated Statement of Income

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

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
Sales and other operating revenues	$	76,192	$	53,545	$	221,813	$	154,191

Sales and other operating revenues in the third quarter and first nine months of 2008 increased $23 billion and $68 billion, respectively, from the year-earlier comparative periods. The increases reflected higher prices for crude oil, natural gas and refined products.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
Income from equity affiliates	$	1,673	$	1,160	$	4,480	$	2,991

Income from equity affiliates increased for the quarterly period on improved upstream-related earnings at Tengizchevroil in Kazakhstan and in Venezuela, due to higher prices for crude oil. Earnings for downstream operations were also higher on improved margins in the Asia-Pacific region. The increase between the nine-month periods was due largely to higher upstream-related earnings at Tengizchevroil due to higher prices for crude oil.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
Other income	$	1,002	$	468	$	1,509	$	2,312

Other income for the quarterly period in 2008 increased due to gains totaling approximately $550 million on U.S. upstream asset sales. Other income for the nine months of 2007 included a $680 million gain on the sale of the company’s investment in Dynegy, approximate gains of $1.1 billion on asset sales in Europe, and an approximate $225 million loss on the redemption of debt.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
Purchased crude oil and products	$	49,238	$	33,988	$	147,822	$	95,253

Purchases increased $15 billion and $53 billion in the quarterly and nine-month periods due to higher prices for crude oil, natural gas and refined products.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
Operating, selling, general and administrative expenses	$	6,954	$	5,843	$	19,643	$	16,227

Operating, selling, general and administrative expenses increased approximately $1.1 billion between the quarterly periods, primarily due to expenses in the 2008 quarter of approximately $700 million associated with damage to facilities caused by hurricanes in the Gulf of Mexico,higher employee costs of about $250 million, and an increase of approximately $150 million related to equipment rentals and other expenses.

Between the nine-month periods, total expenses increased approximately $3.4 billion, primarily due to $1.5 billion of increased costs for materials, services and equipment; higher employee costs of about $800 million; the 2008

30

hurricane-related expenses discussed above; and an increase of about $200 million for environmental remediation activities.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
Exploration expenses	$	271	$	295	$	831	$	874

The decline in exploration expenses between quarters was due to lower amounts for geological and geophysical costs. The decline between the nine-month periods was the result of lower amounts for well write-offs.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
Depreciation, depletion and amortization	$	2,449	$	2,495	$	6,939	$	6,614

Depreciation, depletion and amortization expenses were relatively unchanged between the quarterly periods. The increase between the nine-month periods was associated with higher depreciation rates for certain oil and gas producing fields, reflecting completion of higher-cost development projects and asset retirement obligations.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
Taxes other than on income	$	5,614	$	5,538	$	16,756	$	16,706

Taxes other than on income were relatively unchanged from the 2007 periods.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
Interest and debt expense	$	—	$	22	$	—	$	159

Interest and debt expense was zero in 2008 due to all interest-related amounts being capitalized.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
	(Millions of dollars)
Income tax expense	$	6,416	$	3,249	$	16,681	$	9,776

Refer to Note 6 on page 14 for a discussion of the change in income tax expense between the comparative periods and the change in the associated effective income-tax rates.

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Selected Operating Data

The following table presents a comparison of selected operating data:

Selected Operating Data(1)(2)

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
U.S. Upstream
Net crude-oil and natural-gas-liquids production (MBPD)		409		458		428		462
Net natural-gas production (MMCFPD)(3)		1,431		1,695		1,561		1,707
Net oil-equivalent production (MBOEPD)		647		741		688		747
Sales of natural gas (MMCFPD)		7,142		7,428		7,591		7,810
Sales of natural gas liquids (MBPD)		155		154		156		155
Revenue from net production	��
Crude oil and natural gas liquids ($/Bbl.)	$	107.22	$	66.53	$	100.73	$	57.94
Natural gas ($/MCF)	$	8.64	$	5.43	$	8.66	$	6.13
International Upstream
Net crude-oil and natural-gas-liquids production (MBPD)		1,167		1,274		1,201		1,296
Net natural-gas production (MMCFPD)(3)		3,618		3,288		3,669		3,291
Net oil-equivalent production (MBOEPD)(4)		1,796		1,850		1,838		1,874
Sales of natural gas (MMCFPD)		4,224		3,646		4,201		3,791
Sales of natural gas liquids (MBPD)(5)		105		117		122		116
Revenue from liftings
Crude oil and natural gas liquids ($/Bbl.)	$	102.73	$	67.11	$	99.93	$	59.74
Natural gas ($/MCF)	$	5.37	$	3.78	$	5.21	$	3.75
U.S. and International Upstream
Total net oil-equivalent production, including volumes from oil sands (MBOEPD)(3)(4)		2,443		2,591		2,526		2,621
U.S. Downstream
Gasoline sales (MBPD)(6)		706		731		694		734
Sales of other refined products (MBPD)		716		719		719		734
Total		1,422		1,450		1,413		1,468
Refinery input (MBPD)		922		799		878		804
International Downstream
Gasoline sales (MBPD)(6)		500		481		505		471
Sales of other refined products (MBPD)		1,007		1,056		1,034		1,068
Share of affiliate sales (MBPD)		501		500		503		480
Total		2,008		2,037		2,042		2,019
Refinery input (MBPD)		976		1,043		965		1,018
(1) Includes company share of equity affiliates.
(2) MBPD — thousands of barrels per day; MMCFPD — millions of cubic feet per day; Bbl. — Barrel; MCF — thousands of cubic feet; oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil; MBOEPD — thousands of barrels of oil-equivalent per day.
(3) Includes natural gas consumed in operations (MMCFPD):
United States		69		64		77		62
International		511		422		473		421
(4) Includes production from oil sands — net (MBPD):		26		28		26		30
(5) 2007 conformed to 2008 presentation.
(6) Includes branded and unbranded gasoline.

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Liquidity and Capital Resources

Cash and cash equivalents and marketable securitiestotaled nearly $11 billion at September 30, 2008, up $2.9 billion from year-end 2007. Cash provided by operating activities in the first nine months of 2008 was $24.4 billion, an amount sufficient for capital and exploratory expenditures, dividends on common stock and repurchases of common stock.

Dividends  The company paid dividends of $3.9 billion to common stockholders during the first nine months of 2008. In April 2008, the company increased its quarterly dividend by 12.1 percent to 65 cents per share.

Debt and Capital Lease and Minority Interest Obligations  Chevron’s total debt and capital lease obligations were $7.0 billion at September 30, 2008, down from $7.2 billion at December 31, 2007. The decline was associated with the repayment of $750 million of Chevron Canada Funding Company bonds that matured in February 2008. The company also had minority interest obligations of $211 million at September 30, 2008.

The company’s debt and capital lease obligations due within one year, consisting primarily of commercial paper and the current portion of long-term debt, totaled $5.8 billion at September 30, 2008, and $5.5 billion at December 31, 2007. Of these amounts, approximately $5.0 billion and $4.4 billion were reclassified to long-term at the end of each period, respectively. At September 30, 2008, settlement of these obligations was not expected to require the use of working capital within one year, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

At September 30, 2008, the company had $5 billion in committed credit facilities with various major banks, which permit the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and also can be used for general 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 London Interbank Offered Rate 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 September 30, 2008. In addition, the company has an automatic shelf registration statement that expires in March 2010 for an unspecified amount of non-convertible debt securities issued or guaranteed by the company.

The company has outstanding public bonds issued by Chevron Corporation Profit Sharing/Savings Plan Trust Fund, Texaco Capital Inc. and Union Oil Company of California. All of these securities are guaranteed by Chevron Corporation and are rated AA by Standard and Poor’s Corporation and Aa1 by Moody’s Investors Service. The company’s U.S. commercial paper is ratedA-1+ by Standard and Poor’s andP-1 by Moody’s. 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. The company believes that it has substantial borrowing capacity to meet unanticipated cash requirements and that during periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, it has the flexibility to increase borrowingsand/or modify capital-spending plans to continue paying the common stock dividend and maintain the company’s high-quality debt ratings.

Common Stock Repurchase Program  In September 2007, the company authorized the acquisition of up to $15 billion of its common shares 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 is for a period of up to three years and may be discontinued at any time. The company acquired 23.3 million shares in the open market for $2.0 billion during the third quarter of 2008. From the inception of the program in September 2007 through October 2008, the company had acquired 105 million shares at a cost of $9.1 billion. These amounts include shares acquired in the October 2008 exchange transaction described in “Business Environment and Outlook” on page 23.

Current Ratio — current assets divided by current liabilities. The current ratio was 1.2 at September 30, 2008, and at December 31, 2007. The current ratio is adversely affected by the valuation of Chevron’s inventories on a LIFO basis. At December 31, 2007, the book value of inventory was approximately $7 billion lower than replacement

33

costs, based on average acquisition costs during the year. 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 7.4 percent at September 30, 2008, and 8.6 percent at year-end 2007, respectively.

Pension Obligations  At the end of 2007, the company estimated it would contribute $500 million to employee pension plans during 2008 (composed of $300 million for the U.S. plans and $200 million for the international plans). Through September 30, 2008, a total of $169 million was contributed (including $71 million to the U.S. plans). Total estimated contributions for the full year continue to be $500 million, but the company may contribute an amount that differs from this estimate. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

Capital and Exploratory Expenditures  Total expenditures, including the company’s share of spending by affiliates, were $15.8 billion in the first nine months of 2008, compared with $13.8 billion in the corresponding 2007 period. The amounts included the company’s share of equity-affiliate expenditures of $1.6 billion and $1.7 billion in the 2008 and 2007 periods, respectively. Expenditures for upstream projects in 2008 were about $12.6 billion, representing 80 percent of the companywide total.

Capital and Exploratory Expenditures by Major Operating Area

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
United States
Upstream	$	1,296	$	1,309	$	3,986	$	3,199
Downstream		497		392		1,397		950
Chemicals		195		52		322		119
All Other		153		163		418		559
Total United States		2,141		1,916		6,123		4,827
International
Upstream		2,938		2,859		8,661		7,685
Downstream		395		423		949		1,232
Chemicals		18		13		40		35
All Other		1		1		4		4
Total International		3,352		3,296		9,654		8,956
Worldwide	$	5,493	$	5,212	$	15,777	$	13,783

Contingencies and Significant Litigation

MTBE  Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. In October 2008, 59 cases were settled in which the company was a party and which related to the use of MTBE in certain oxygenated gasolines and the alleged seepage of MTBE into groundwater. The terms of this agreement are confidential and not material to the company’s results of operations, liquidity or financial position.

Chevron is a party to 32 other pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims 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 settlement of the 59 lawsuits did not set any precedents related to standards of liability to be used to

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judge the merits of the claims, corrective measures required or monetary damages to be assessed for the remaining lawsuits and claims or future lawsuits and claims. As a result, the company’s ultimate exposure related to pending lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company no longer uses MTBE in the manufacture of gasoline in the United States.

RFG Patent  Fourteen purported class actions were brought by consumers who purchased reformulated gasoline (RFG) from January 1995 through August 2005, alleging that Unocal misled the California Air Resources Board into adopting standards for composition of RFG that overlapped with Unocal’s undisclosed and pending patents. The parties have finalized settlement of all these matters. On August 14, 2008, the United States District Court for the Central District of California granted plaintiffs’ motion for preliminary approval of aclass-action settlement. The settlement calls for, among other things, Unocal to pay $48 million, and for the establishment of acy presfund to administer payout of the award. Plaintiffs’ motion for the court’s final approval is scheduled for November 24, 2008.

Ecuador  Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations, and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium, and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpet’s ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40 million. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations.

Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs bring the action, enacted in 1999, cannot be applied retroactively to Chevron; third, that the claims are barred by the statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador. With regard to the facts, the Company believes that the evidence confirms that Texpet’s remediation was properly conducted and that the remaining environmental damage reflects Petroecuador’s failure to timely fulfill its legal obligations and Petroecuador’s further conduct since assuming full control over the operations.

In April 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $8 billion, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, healthcare systems, and additional infrastructure for Petroecuador. The engineer’s report also asserts that an additional $8.3 billion could be assessed against Chevron for unjust enrichment. The engineer’s report is not binding on the court. Chevron also believes that the engineer’s work was performed, and his report prepared, in a manner contrary to law and in violation of the court’s orders. Chevron has submitted a rebuttal to the report in which it asks the court to strike the report in its entirety, and Chevron will continue a vigorous defense of any attempted imposition of liability.

Management does not believe an estimate of a reasonably possible loss (or a range of loss) can be made in this case. Due to the defects associated with the engineer’s report, management does not believe the report itself has any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to estimate a reasonably possible loss (or a range of loss).

Guarantees  The company and its subsidiaries have certain other contingent liabilities with respect to guarantees, direct or indirect, of debt of affiliated companies or third parties. Under the terms of the guarantee arrangements,

35

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 may have recourse provisions that would enable the company to recover any payments made under the terms of the guarantees from assets provided as collateral.

Off-Balance-Sheet Obligations  The company and its subsidiaries have certain other contractual obligations relating to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline, storage and regasification capacity, drilling rigs, utilities and petroleum products, to be used or sold in the ordinary course of the company’s business.

Indemnifications  The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. The company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make future payments up to $300 million. Through the end of September 2008, the company paid $48 million under these indemnities and continues to be obligated for possible additional 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 interest 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 must be asserted no later than February 2009 for Equilon indemnities and no later than February 2012 for Motiva indemnities. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments. The company has not recorded any liabilities for possible claims under these indemnities. The company posts no assets as collateral and has made no payments under the indemnities.

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

In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. Under the indemnification agreement, the company’s liability is unlimited until April 2022, when the liability expires. The acquirer of the assets sold in 1997 shares in certain environmental remediation costs up to a maximum obligation of $200 million, which had not been reached as of September 30, 2008.

Securitization  During the third quarter 2008, the company terminated the program used to securitize downstream-related trade accounts receivable. At year-end 2007, the balance of securitized receivables was $675 million. As of September 30, 2008, the company had no other securitization arrangements in place.

Minority Interests  The company has commitments of $211 million related to minority interests in subsidiary companies.

Environmental  The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals 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, land development areas, and mining operations, 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

36

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 chemical companies.

Chevron’s environmental reserve at December 31, 2007, was approximately $1.5 billion. At September 30, 2008, the environmental reserve was approximately $1.9 billion. The increase was mainly associated with remediation liabilities Chevron has incurred for sites that were previously sold.

Financial Instruments  The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodities and other derivatives activities, includingforward-exchange contracts and interest rate swaps.

Income Taxes  Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions, examinations of tax returns for certain prior tax years had not been completed as of September 30, 2008. For Chevron’s major tax jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States — 2003, Nigeria — 1994, Angola — 2001 and Saudi Arabia — 2003.

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

The Emergency Economic Stabilization Act of 2008 (EESA), the Energy Improvement and Extension Act of 2008 (EIEA), the Energy and Tax Extenders Act of 2008 and the Alternative Minimum Tax Relief Act of 2008 (collectively, the Acts), were signed into U.S. law on October 3, 2008. The EIEA freezes at 6 percent the deduction for oil and natural-gas manufacturing income that was scheduled to increase to 9 percent in 2010. The deduction is still scheduled to increase to 9 percent in 2010 for all other manufacturers. The company is reviewing other provisions of the Acts to determine any possible additional financial impacts.

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, 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. For this range of settlement, Chevron estimates its maximum possible net before-tax liability at approximately $200 million, and the possible maximum net amount that could be owed to Chevron is estimated at about $150 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

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

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

New Accounting Standards

FASB Statement No. 141 (revised 2007), Business Combinations(FAS 141-R)  In December 2007, the FASB issuedFAS 141-R, which will become effective for business combination transactions having an acquisition date on or after January 1, 2009. This standard requires the acquiring entity in a business combination to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date to be measured at their respective fair values. The statement requires acquisition-related costs, as well as restructuring costs the acquirer expects to incur for which it is not obligated at acquisition date, to be recorded against income

37

rather than included in purchase-price determination. It also requires recognition of contingent arrangements at their acquisition-date fair values, with subsequent changes in fair value generally reflected in income.

FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (FAS 160)  The FASB issued FAS 160 in December 2007, which will become effective for the company January 1, 2009, with retroactive adoption of the Statement’s presentation and disclosure requirements for existing minority interests. This standard will require ownership interests in subsidiaries held by parties other than the parent to be presented within the equity section of the consolidated statement of financial position but separate from the parent’s equity. It will also require the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the Consolidated Statement of Income. Certain changes in a parent’s ownership interest are to be accounted for as equity transactions and when a subsidiary is deconsolidated, any noncontrolling equity investment in the former subsidiary is to be initially measured at fair value. The company does not anticipate the implementation of FAS 160 will significantly change the presentation of its Consolidated Statement of Income or Consolidated Balance Sheet.

FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities (FAS 161)  In March 2008, the FASB issued FAS 161, which becomes effective for the company on January 1, 2009. This standard amends and expands the disclosure requirements of FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities. FAS 161 requires disclosures related to objectives and strategies for using derivatives; the fair-value amounts of, and gains and losses on, derivative instruments; and credit-risk-related contingent features in derivative agreements. The effect on the company’s disclosures for derivative instruments as a result of the adoption of FAS 161 in 2009 will depend on the company’s derivative instruments and hedging activities at that time.

Item 3.   Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the three months ended September 30, 2008, does not differ materially from that discussed under Item 7A of Chevron’s 2007 Annual Report onForm 10-K/A.

Item 4.   Controls and Procedures

(a) Evaluation of disclosure controls and procedures

Chevron management has evaluated, with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures (as defined inRule 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the company’s disclosure controls and procedures were effective as of September 30, 2008.

(b) Changes in internal control over financial reporting

During the quarter ended September 30, 2008, there were no changes in the company’s internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, the company’s internal control over financial reporting.

PART II

OTHER INFORMATION

Item 1.   Legal Proceedings

None

Item 1A.   Risk Factors

Chevron is a major fully integrated petroleum company with a diversified business portfolio, strong balance sheet, and history of generating sufficient cash to fund capital and exploratory expenditures and to pay dividends.

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Nevertheless, some inherent risks could materially impact the company’s financial results of operations or financial condition.

Information about risk factors for the three months ended September 30, 2008, does not differ materially from that set forth in Part I, Item 1A, of Chevron’s 2007 Annual Report onForm 10-K/A.

Item 2.   Unregistered Sales of Equity Securities and Use of Proceeds

CHEVRON CORPORATION

ISSUER PURCHASES OF EQUITY SECURITIES

							Maximum
	Total				Total Number of		Number of Shares
	Number of		Average		Shares Purchased as		that May Yet Be
	Shares		Price Paid		Part of Publicly		Purchased Under
Period	Purchased(1)		per Share		Announced Program		the Program
July 1-31, 2008		2,788,866		97.52		2,780,000		—
August 1-31, 2008		9,138,119		85.28		9,135,000		—
September 1-30, 2008		11,421,734		83.19		11,416,933		—
Total		23,348,719		85.72		23,331,933		(2	)

(1)

Includes 5,372 common shares repurchased during the three-month period ended September 30, 2008, 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 long-term incentive plans. Also includes 11,414 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 September 30, 2008.

(2)

In September 2007, the company authorized common stock repurchases of up to $15 billion that may 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 September 30, 2008, $8.1 billion had been expended to repurchase 90,778,902 shares since the common stock repurchase program began.

Item 5.   Other Information

Rule 10b5-1 Plan Elections

Mr. Peter J. Robertson, Vice Chairman of Chevron Corporation, entered into a pre-arranged stock trading plan in September 2008, as a part of his long-term strategy for asset diversification. It provides for the potential exercise of vested stock options and the associated sale of up to 200,000 shares of Chevron common stock between December 1, 2008 and August 31, 2009. The trading plan was entered into during the last open insider trading window and is intended to satisfyRule 10b5-1(c) of the Securities Exchange Act of 1934, as amended, and Chevron’s policies regarding transactions in Chevron securities.

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Item 6.   Exhibits

Exhibit
Number	Description
(4)	Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Commission upon request.
(4.1)	Instrument of Resignation, Appointment and Acceptance, Debt Trustee — Chevron Canada Funding Company
(4.2)	Instrument of Resignation, Appointment and Acceptance, Debt Trustee — Chevron Funding Corporation
(4.3)	Instrument of Resignation, Appointment and Acceptance, Debt Trustee — Chevron Corporation
(12.1)	Computation of Ratio of Earnings to Fixed Charges
(31.1)	Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer
(31.2)	Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer
(32.1)	Section 1350 Certification by the company’s Chief Executive Officer
(32.2)	Section 1350 Certification by the company’s Chief Financial Officer
(100.INS)	XBRL Instance Document
(100.SCH)	XBRL Schema Document
(100.CAL)	XBRL Calculation Linkbase Document
(100.LAB)	XBRL Label Linkbase Document
(100.PRE)	XBRL Presentation Linkbase Document
(100.DEF)	XBRL Definition Linkbase Document

Pursuant to Rule 401 ofRegulation S-T, the purpose of submitting the XBRL-related documents is to test the related format and technology and, as a result, investors and others should continue to rely on the official version of the filing and not rely on the XBRL-related documents in making investment decisions. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

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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: November 6, 2008

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EXHIBIT INDEX

Exhibit
Number	Description
(4)	Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Commission upon request.
(4.1)*	Instrument of Resignation, Appointment and Acceptance, Debt Trustee — Chevron Canada Funding Company
(4.2)*	Instrument of Resignation, Appointment and Acceptance, Debt Trustee — Chevron Funding Corporation
(4.3)*	Instrument of Resignation, Appointment and Acceptance, Debt Trustee — Chevron Corporation
(12.1)*	Computation of Ratio of Earnings to Fixed Charges
(31.1)*	Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer
(31.2)*	Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer
(32.1)*	Section 1350 Certification by the company’s Chief Executive Officer
(32.2)*	Section 1350 Certification by the company’s Chief Financial Officer
(100.INS)*	XBRL Instance Document
(100.SCH)*	XBRL Schema Document
(100.CAL)*	XBRL Calculation Linkbase Document
(100.LAB)*	XBRL Label Linkbase Document
(100.PRE)*	XBRL Presentation Linkbase Document
(100.DEF)*	XBRL Definition Linkbase Document

Pursuant to Rule 401 ofRegulation S-T, the purpose of submitting the XBRL-related documents is to test the related format and technology and, as a result, investors and others should continue to rely on the official version of the filing and not rely on the XBRL-related documents in making investment decisions. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

* 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, California94583-2324.

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