Chevron (CVX) 10-Q 2006 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, 2006
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-368-2

Chevron Corporation

(Exact name of registrant as specified in its charter)

Delaware	94-0890210
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)
6001 Bollinger Canyon Road, San Ramon, California	94583-2324
(Address of principal executive offices)	(Zip Code)

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

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. Yesþ          No o

      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act. (Check one):

      Large accelerated filer þ          Accelerated filer o          Non-accelerated filer  o

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

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

Class	Outstanding as of September 30, 2006
Common stock, $.75 par value	2,179,982,547

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, 2006, and 2005		3
	Consolidated Statement of Comprehensive Income for the Three and Nine Months Ended September 30, 2006, and 2005		4
	Consolidated Balance Sheet at September 30, 2006, and December 31, 2005		5
	Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2006, and 2005		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		39
Item 1A.	Risk Factors		39
Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		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

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

      Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are crude oil and natural gas prices; refining margins and marketing margins; chemicals prices and competitive conditions affecting supply and demand for aromatics, olefins and additives products; actions of competitors; the competitiveness of alternate energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction orstart-up of planned projects; potential disruption or interruption of the company’s net production or manufacturing facilities due to war, accidents, political events, civil unrest or severe weather; potential liability for remedial actions under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; potential liability resulting from pending or future litigation; the company’s acquisition or disposition of assets; government-mandated sales, divestitures, recapitalizations, changes in fiscal terms or restrictions on scope of company operations; the effects of changed accounting standards under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” on pages 31 and 32 of the company’s 2005 Annual Report on Form 10-K. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

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
			2006		2005		2006		2005
			(Millions of dollars, except per-share amounts)
Revenues and Other Income
Sales and other operating revenues(1)(2)			$	52,977	$	53,429	$	158,654	$	141,184
Income from equity affiliates				1,080		871		3,176		2,621
Other income				155		156		542		601
	Total Revenues and Other Income			54,212		54,456		162,372		144,406
Costs and Other Deductions
Purchased crude oil and products(2)				32,076		36,101		100,493		93,722
Operating expenses				3,650		3,190		10,532		8,372
Selling, general and administrative expenses				1,428		1,337		3,890		3,488
Exploration expenses				284		177		817		469
Depreciation, depletion and amortization				1,923		1,534		5,518		4,188
Taxes other than on income(1)				5,403		5,282		15,350		15,719
Interest and debt expense				104		136		359		347
Minority interests				20		24		68		63
	Total Costs and Other Deductions			44,888		47,781		137,027		126,368
Income Before Income Tax Expense				9,324		6,675		25,345		18,038
Income Tax Expense				4,307		3,081		11,979		8,083
Net Income			$	5,017	$	3,594	$	13,366	$	9,955
Per Share of Common Stock:
	Net Income
		— Basic	$	2.30	$	1.65	$	6.09	$	4.70
		— Diluted	$	2.29	$	1.64	$	6.06	$	4.68
	Dividends		$	0.52	$	0.45	$	1.49	$	1.30
	Weighted Average Number of Shares Outstanding (000s)
		— Basic		2,178,472		2,181,387		2,196,062		2,116,912
		— Diluted		2,189,688		2,193,851		2,206,385		2,127,356
(1) Includes excise, value-added and other similar taxes:			$	2,522	$	2,268	$	7,053	$	6,546
(2) Includes amounts in revenues for buy/sell contracts; associated costs are in “Purchased crude oil and products.” Refer to Note 15 on page 20:			$	—	$	6,588	$	6,725	$	17,925

Refer to 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
					2006			2005			2006			2005
					(Millions of dollars)
Net Income					$	5,017		$	3,594		$	13,366		$	9,955
	Currency translation adjustment					(1	)		(8	)		39			(3	)
	Unrealized holding (loss) gain on securities:
		Net (loss) gain arising during period				—			(4	)		2			(13	)
		Reclassification to net income of net realized loss (gain)				10			—			(95	)		—
		Total				10			(4	)		(93	)		(13	)
		Net derivatives (loss) gain on hedge transactions:
			Net (loss) gain on hedge transactions
				Before income taxes		1			(215	)		1			(253	)
				Income taxes		1			79			4			93
			Reclassification to net income of net realized loss:
				Before income taxes		6			—			81			—
				Income taxes		(5	)		—			(31	)		—
		Total				3			(136	)		55			(160	)
	Minimum pension liability adjustment					1			—			—			1
Other Comprehensive Income (Loss), net of tax						13			(148	)		1			(175	)
Comprehensive Income					$	5,030		$	3,446		$	13,367		$	9,780

Refer to accompanying notes to consolidated financial statements.

4

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

				At September 30			At December 31
				2006			2005
				(Millions of dollars, except
				per-share amounts)
ASSETS
Cash and cash equivalents				$	11,226		$	10,043
Marketable securities					1,047			1,101
Accounts and notes receivable, net					18,738			17,184
Inventories:
	Crude oil and petroleum products				4,159			3,182
	Chemicals				278			245
	Materials, supplies and other				770			694
		Total inventories			5,207			4,121
Prepaid expenses and other current assets					2,206			1,887
		Total Current Assets			38,424			34,336
Long-term receivables, net					2,305			1,686
Investments and advances					17,637			17,057
Properties, plant and equipment, at cost					134,689			127,446
Less: accumulated depreciation, depletion and amortization					67,801			63,756
		Properties, plant and equipment, net			66,888			63,690
Deferred charges and other assets					4,208			4,428
Goodwill					4,659			4,636
			Total Assets	$	134,121		$	125,833
LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt				$	2,289		$	739
Accounts payable					17,065			16,074
Accrued liabilities					3,940			3,690
Federal and other taxes on income					4,366			3,127
Other taxes payable					1,382			1,381
		Total Current Liabilities			29,042			25,011
Long-term debt					7,822			11,807
Capital lease obligations					282			324
Deferred credits and other noncurrent obligations					10,894			10,507
Noncurrent deferred income taxes					12,462			11,262
Reserves for employee benefit plans					3,790			4,046
Minority interests					227			200
		Total Liabilities			64,519			63,157
Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued)					—			—
Common stock (authorized 4,000,000,000 shares, $.75 par value, 2,442,676,580 shares issued at September 30, 2006, and December 31, 2005)					1,832			1,832
Capital in excess of par value					14,111			13,894
Retained earnings					65,815			55,738
Notes receivable — key employees					(2	)		(3	)
Accumulated other comprehensive loss					(428	)		(429	)
Deferred compensation and benefit plan trust					(474	)		(486	)
Treasury stock, at cost (262,694,033 and 209,989,910 shares at September 30, 2006, and December 31, 2005, respectively)					(11,252	)		(7,870	)
		Total Stockholders’ Equity			69,602			62,676
			Total Liabilities and Stockholders’ Equity	$	134,121		$	125,833

Refer to accompanying notes to consolidated financial statements.

5

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

				Nine Months Ended
				September 30
				2006			2005
				(Millions of dollars)
Operating Activities
	Net income			$	13,366		$	9,955
	Adjustments
		Depreciation, depletion and amortization			5,518			4,188
		Dry hole expense			278			155
		Distributions less than income from equity affiliates			(661	)		(861	)
		Net before-tax gains on asset retirements and sales			(63	)		(142	)
		Net foreign currency effects			291			35
		Deferred income tax provision			765			733
		Net increase in operating working capital			(52	)		(192	)
		Minority interest in net income			68			63
		Increase in long-term receivables			(582	)		(98	)
		Decrease in other deferred charges			410			489
		Cash contributions to employee pension plans			(219	)		(119	)
		Other			(540	)		(39	)
			Net Cash Provided by Operating Activities		18,579			14,167
Investing Activities
		Acquisition of Unocal Corporation, net of Unocal cash received			—			(5,934	)
		Capital expenditures			(9,667	)		(5,476	)
		Proceeds from asset sales			640			2,490
		Net sales of marketable securities			48			263
		Repayment of loans by equity affiliates			53			48
		Redemption of securities by equity affiliates			400			—
			Net Cash Used for Investing Activities		(8,526	)		(8,609	)
Financing Activities
		Net (payments) borrowings of short-term obligations			(476	)		19
		Repayments of long-term debt and other financing obligations			(1,873	)		(123	)
		Cash dividends			(3,274	)		(2,778	)
		Dividends paid to minority interests			(40	)		(66	)
		Net purchases of treasury shares			(3,351	)		(1,870	)
		Redemption of preferred stock of subsidiary			—			(140	)
		Proceeds from issuance of long-term debt			—			20
			Net Cash Used For Financing Activities		(9,014	)		(4,938	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents					144			(103	)
Net Change in Cash and Cash Equivalents					1,183			517
Cash and Cash Equivalents at January 1					10,043			9,291
Cash and Cash Equivalents at September 30				$	11,226		$	9,808

Refer to 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 independent accountants. In the opinion of the company’s management, the interim data include all adjustments necessary for a fair statement of the results for the interim periods. These adjustments were of a normal recurring nature, except for the items described in Note 2.

      Certain notes and other information have been condensed or omitted from the interim financial statements presented in this Quarterly Report on Form 10-Q. Therefore, these financial statements should be read in conjunction with the company’s 2005 Annual Report on Form 10-K.

      The results for the three- and nine-month periods ended September 30, 2006, are not necessarily indicative of future financial results.

Note 2. Acquisition of Unocal Corporation

      On August 10, 2005, the company acquired Unocal Corporation, an independent oil and gas exploration and production company. Unocal’s principal upstream operations were in North America and Asia, including the Caspian region. Also located in Asia was Unocal’s geothermal energy business. Other activities included ownership interests in proprietary and common carrier pipelines, natural gas storage facilities and mining operations.

      The aggregate purchase price of Unocal was $17.3 billion. A third-party appraisal firm was engaged to assist the company in the process of determining the fair values of Unocal’s tangible and intangible assets. The final purchase-price allocation to the assets and liabilities acquired was completed as of June 30, 2006.

      The acquisition was accounted for under the rules of Financial Accounting Standards Board (FASB) Statement No. 141,“Business Combinations.”The following table summarizes the final purchase-price allocation:

		Millions of dollars
Current assets		$	3,573
Investments and long-term receivables			1,695
Properties			17,285
Goodwill			4,820
Other assets			2,174
	Total assets acquired		29,547
Current liabilities			(2,364	)
Long-term debt and capital leases			(2,392	)
Deferred income taxes			(4,009	)
Other liabilities			(3,494	)
	Total liabilities assumed		(12,259	)
	Net assets acquired	$	17,288

      The $4.8 billion of goodwill, which represents benefits of the acquisition that are additional to the fair values of the other net assets acquired, was assigned to the upstream segment. The goodwill is not deductible for tax purposes. The goodwill balance was reviewed for possible impairment as of June 30, 2006, according to the requirements of FASB Statement No. 142,“Goodwill and Other Intangible Assets,”to test goodwill for impairment on an annual basis. Goodwill was determined not to be impaired at that time, and no events have occurred subsequently that would necessitate an additional impairment review.

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 3. Information Relating to the Statement of Cash Flows

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

		Nine Months Ended
		September 30
		2006			2005
		(Millions of dollars)
Increase in accounts and notes receivable		$	(1,130	)	$	(3,725	)
Increase in inventories			(1,087	)		(402	)
Decrease (increase) in prepaid expenses and other current assets			20			(144	)
Increase in accounts payable and accrued liabilities			1,105			3,155
Increase in income and other taxes payable			1,040			924
	Net increase in operating working capital	$	(52	)	$	(192	)

      In accordance with the cash-flow classification requirements of FAS 123R,“Share-Based Payment,”the “Net increase in operating working capital” includes reductions of $60 million and $24 million for excess income tax benefits associated with stock options exercised during the first nine months of 2006 and 2005, respectively. These amounts are offset by “Net purchases of treasury shares.” Refer to Note 9 beginning on page 15 for additional information related to the company’s adoption of FAS 123R,“Share-Based Payment.”

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

	Nine Months Ended
	September 30
	2006		2005
	(Millions of dollars)
Interest on debt (net of capitalized interest)	$	402	$	319
Income taxes		10,144		5,894

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

		Nine Months Ended
		September 30
		2006			2005
		(Millions of dollars)
Marketable securities purchased		$	(820	)	$	(665	)
Marketable securities sold			868			928
	Net sales of marketable securities	$	48		$	263

      The “Net purchases of treasury shares” represents the cost of common shares acquired in the open market less the cost of shares issued for share-based compensation plans. Open-market purchases totaled $3.7 billion and $2.2 billion in the 2006 and 2005 periods, respectively. Purchases in the first nine months of 2006 were under the company’s stock repurchase program initiated in December 2005. The 2005 purchases related to a program that began in April 2004 and was completed in November 2005.

      In May 2006, the company’s investment in Dynegy Series C preferred stock was redeemed at its face value of $400 million. Upon redemption of the preferred stock, the company recorded a gain of $130 million, of which $105 million was reclassified from “Other Comprehensive Income.” The $130 million gain is included in the Consolidated Statement of Income as “Income from equity affiliates.”

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

		Nine Months Ended
		September 30
		2006			2005
		(Millions of dollars)
Additions to properties, plant and equipment		$	8,834		$	5,158
Additions to investments			780			275
Current year dry hole expenditures			175			128
Payments for other liabilities and assets, net			(122	)		(85	)
	Capital expenditures		9,667			5,476
Other exploration expenditures			539			314
Assets acquired through capital lease obligations			20			153
	Capital and exploratory expenditures, excluding equity affiliates		10,226			5,943
Share of expenditures by equity affiliates			1,261			1,144
	Capital and exploratory expenditures, including equity affiliates	$	11,487		$	7,087

Note 4. 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, downstream, chemicals and all other. The first three of these groupings represent the company’s “reportable segments” and “operating segments” as defined in FAS 131,“Disclosures about Segments of an Enterprise and Related Information.”

      The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) (terms as defined in FAS 131). The CODM is the company’s Executive Committee, a committee of senior officers that includes the chief executive officer, and 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 for the monitoring of the segment’s operating activities and financial performance. The CODM approves annual capital and exploratory budgets at the reportable segment level, as well as reviews capital and exploratory funding for major projects and approves major changes to the annual capital and exploratory budgets. However, business-unit managers within the operating segments are directly responsible for decisions relating to project implementation and all other matters connected with daily operations. Company officers who are members of the Executive Committee also have individual management responsibilities and participate on other committees for purposes other than acting as the CODM.

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

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

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All Other.” Income by operating segment for the three-and nine-month periods ended September 30, 2006 and 2005, is presented in the following table:

Segment Income

		Three Months Ended						Nine Months Ended
		September 30						September 30
		2006			2005			2006			2005
		(Millions of dollars)
Upstream
	United States	$	1,269		$	1,206		$	3,384		$	2,945
	International		2,234			2,117			6,849			5,529
Total Upstream			3,503			3,323			10,233			8,474
Downstream
	United States		831			139			1,595			595
	International		610			434			1,424			1,363
Total Downstream			1,441			573			3,019			1,958
Chemicals
	United States		134			(7	)		338			185
	International		34			13			77			42
Total Chemicals			168			6			415			227
Total Segment Income			5,112			3,902			13,667			10,659
All Other
	Interest Expense		(72	)		(94	)		(248	)		(242	)
	Interest Income		107			73			280			187
	Other		(130	)		(287	)		(333	)		(649	)
Net Income		$	5,017		$	3,594		$	13,366		$	9,955

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Segment AssetsSegment assets do not include intercompany investments or intercompany receivables. “All Other” assets consist primarily of worldwide cash, cash equivalents and marketable securities, real estate, information systems, the company’s investment in Dynegy, mining operations of coal and other minerals, power generation businesses, technology companies and assets of the corporate administrative functions. Segment assets at September 30, 2006, and December 31, 2005 follow:

Segment Assets

		At September 30		At December 31
		2006		2005
		(Millions of dollars)
Upstream
	United States	$	19,991	$	19,006
	International		49,772		46,501
	Goodwill		4,659		4,636
Total Upstream			74,422		70,143
Downstream
	United States		14,105		12,273
	International		24,447		22,294
Total Downstream			38,552		34,567
Chemicals
	United States		2,601		2,452
	International		789		727
Total Chemicals			3,390		3,179
Total Segment Assets			116,364		107,889
All Other
	United States		8,527		9,234
	International		9,230		8,710
Total All Other			17,757		17,944
Total Assets — United States			45,224		42,965
Total Assets — International			84,238		78,232
Goodwill			4,659		4,636
Total Assets		$	134,121	$	125,833

     Segment Sales and Other Operating RevenuesUpstream segment revenues 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, kerosene, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the transportation and trading of crude oil and refined products. Revenues for the chemicals segment are derived primarily from the manufacture and sale of additives for lubricants and fuels. “All Other” activities include revenues from mining operations of coal and other minerals, power generation businesses, insurance operations, real estate activities and technology companies.

11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Operating-segment sales and other operating revenues, including internal transfers, for the three- and nine-month periods ended September 30, 2006 and 2005, are presented in the following table. Products are transferred between operating segments at internal product values that approximate market prices.

Sales and Other Operating Revenues

			Three Months Ended						Nine Months Ended
			September 30						September 30
			2006			2005			2006			2005
			(Millions of dollars)
Upstream
	United States		$	7,470		$	6,852		$	21,683		$	16,416
	International			8,400			6,740			24,286			16,868
		Sub-total		15,870			13,592			45,969			33,284
	Intersegment Elimination — United States			(2,786	)		(2,384	)		(7,650	)		(6,252	)
	Intersegment Elimination — International			(4,828	)		(3,889	)		(13,073	)		(9,800	)
Total Upstream				8,256			7,319			25,246			17,232
Downstream
	United States			18,985			22,604			59,131			58,785
	International			25,344			23,149			73,209			64,031
		Sub-total		44,329			45,753			132,340			122,816
	Intersegment Elimination — United States			(141	)		(88	)		(401	)		(180	)
	Intersegment Elimination — International			(11	)		(1	)		(27	)		(10	)
Total Downstream				44,177			45,664			131,912			122,626
Chemicals
	United States			161			127			469			427
	International			304			236			848			686
		Sub-total		465			363			1,317			1,113
	Intersegment Elimination — United States			(64	)		(50	)		(180	)		(163	)
	Intersegment Elimination — International			(40	)		(33	)		(122	)		(97	)
Total Chemicals				361			280			1,015			853
All Other
	United States			347			284			918			780
	International			17			22			49			63
		Sub-total		364			306			967			843
	Intersegment Elimination — United States			(176	)		(131	)		(469	)		(352	)
	Intersegment Elimination — International			(5	)		(9	)		(17	)		(18	)
Total All Other				183			166			481			473
Sales and Other Operating Revenues
	United States			26,963			29,867			82,201			76,408
	International			34,065			30,147			98,392			81,648
		Sub-total		61,028			60,014			180,593			158,056
	Intersegment Elimination — United States			(3,167	)		(2,653	)		(8,700	)		(6,947	)
	Intersegment Elimination — International			(4,884	)		(3,932	)		(13,239	)		(9,925	)
Total Sales and Other Operating Revenues*			$	52,977		$	53,429		$	158,654		$	141,184

* Includes amounts in revenues for buy/sell contracts: $ — $ 6,588 $ 6,725 $ 17,925

Substantially all of the amounts in each period related to the downstream segment. Refer to Note 15 on page 20 for a discussion on the company’s adoption of EITF 04-13,“Accounting for Purchases and Sales of Inventory with the Same Counterparty.”

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5. Restructuring and Reorganization

      In connection with the Unocal acquisition, the company implemented a restructuring and reorganization program as part of the effort to capture the synergies of the combined companies. The program is expected to be substantially completed by the end of 2006 and is aimed at eliminating redundant operations, consolidating offices and facilities and sharing common services and functions.

      As part of the restructuring and reorganization, approximately 600 employees were eligible for severance payments. Most of the associated positions were in the United States and related primarily to corporate and upstream executive and administrative functions. By the end of the third quarter 2006, more than 500 of these employees had been terminated.

      In connection with this restructuring and reorganization, an accrual of $106 million was established as part of the purchase accounting for the Unocal acquisition. Activity through first nine months of 2006 for this accrual is shown in the table below. The balance at September 30, 2006, was classified as a current liability on the Consolidated Balance Sheet.

	Amounts before tax
	(Millions of dollars)
Balance at January 1, 2006	$	44
Adjustments		(7	)
Payments		(17	)
Balance at September 30, 2006	$	20

      Shown in the table below is the activity during the first nine months of 2006 for the company’s liability related to various other reorganizations and restructurings across several businesses and corporate departments. The balance at September 30, 2006, was categorized as a current liability on the Consolidated Balance Sheet.

	Amounts before tax
	(Millions of dollars)
Balance at January 1, 2006	$	47
Adjustments		(8	)
Payments		(20	)
Balance at September 30, 2006	$	19

Note 6. Summarized Financial Data — Chevron U.S.A. Inc.

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

	Nine Months Ended
	September 30
	2006		2005
	(Millions of dollars)
Sales and other operating revenues	$	114,570	$	101,506
Costs and other deductions		108,081		97,397
Net income		4,424		2,905

13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	At September 30		At December 31
	2006		2005
	(Millions of dollars)
Current assets	$	31,385	$	27,878
Other assets		22,374		20,611
Current liabilities		23,736		20,286
Other liabilities		10,352		12,897
Net equity	$	19,671	$	15,306
Memo: Total debt	$	6,024	$	8,353

Note 7. Summarized Financial Data — Chevron Transport Corporation

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

	Three Months					Nine Months
	Ended					Ended
	September 30					September 30
	2006		2005			2006		2005
	(Millions of dollars)
Sales and other operating revenues	$	175	$	100		$	505	$	432
Costs and other deductions		149		108			445		338
Net income (loss)		27		(3	)		60		31

	At September 30		At December 31
	2006		2005
	(Millions of dollars)
Current assets	$	353	$	358
Other assets		333		283
Current liabilities		96		119
Other liabilities		248		243
Net equity	$	342	$	279

      There were no restrictions on CTC’s ability to pay dividends or make loans or advances at September 30, 2006.

Note 8. Income Taxes

      Taxes on income for the third quarter and first nine months of 2006 were $4.3 billion and $12 billion, respectively, compared with $3.1 billion and $8.1 billion for the comparable periods in 2005. The associated effective tax rate was 46 percent for the third quarters of 2006 and 2005. For the comparative nine-month periods, the effective tax rates were 47 percent and 45 percent, respectively. The higher tax rate in the 2006 nine-month period included the effect of one-time charges totaling $300 million, including an increase in tax rates on upstream operations in the U.K. North Sea.

14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 9. Stock Options and Other Share-Based Compensation

      Effective July 1, 2005, the company adopted the provisions of Financial Accounting Standards Board (FASB) Statement No. 123R,“Share-Based Payment,” (FAS 123R) for its share-based compensation plans. The company previously accounted for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25,“Accounting for Stock Issued to Employees,”(APB 25) and related interpretations and disclosure requirements established by FAS 123,“Accounting for Stock-Based Compensation.”

      The company adopted FAS 123R using the modified prospective method and accordingly, results for prior periods were not restated. The following table illustrates the effect on net income and earnings per share as if the company had applied the fair-value recognition provisions of FAS 123 to stock options, stock appreciation rights, performance units and restricted stock units for periods prior to adoption of FAS 123R.

	Nine Months Ended
	September 30
	2005
	(Millions of dollars, except
	per-share amounts)
Net income, as reported	$	9,955
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		57
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for awards, net of related tax effects		(83	)
Pro forma net income	$	9,929
Net income per share:
Basic — as reported	$	4.70
Basic — pro forma	$	4.69
Diluted — as reported	$	4.68
Diluted — pro forma	$	4.67

Note 10. Employee Benefits

      The company has defined benefit pension plans for many employees. The company typically pre-funds 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 tax-exempt plans subject to the Employee Retirement Income Security Act of 1974 (ERISA) minimum funding standard. The company does not typically fund domestic nonqualified tax-exempt pension plans that are not subject to funding requirements under 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. For retiree medical coverage in the company’s main U.S. plan, the increase to the company contributions is limited to no more than 4 percent each year, effective at retirement. Certain life insurance benefits are paid by the company and annual contributions are based on actual plan experience.

15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The components of net periodic benefit costs for 2006 and 2005 were:

			Three Months Ended						Nine Months Ended
			September 30						September 30
			2006			2005			2006			2005
			(Millions of dollars)
Pension Benefits
United States
	Service cost		$	57		$	58		$	171		$	149
	Interest cost			121			102			347			285
	Expected return on plan assets			(138	)		(115	)		(414	)		(323	)
	Amortization of prior-service costs			12			12			35			34
	Recognized actuarial losses			28			55			107			134
	Settlement losses			38			18			59			70
		Total United States		118			130			305			349
International
	Service cost			26			21			75			63
	Interest cost			57			51			160			149
	Expected return on plan assets			(61	)		(53	)		(164	)		(157	)
	Amortization of transitional liabilities			1			—			1			1
	Amortization of prior-service costs			4			4			10			12
	Recognized actuarial losses			18			13			51			38
		Total International		45			36			133			106
Net Periodic Pension Benefit Costs			$	163		$	166		$	438		$	455
Other Benefits*
	Service cost		$	7		$	8		$	27		$	22
	Interest cost			46			42			133			120
	Amortization of prior-service costs			(20	)		(23	)		(66	)		(68	)
	Recognized actuarial losses			22			23			77			69
Net Periodic Other Benefit Costs			$	55		$	50		$	171		$	143

*  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 2005, the company estimated it would contribute $300 million and $200 million to its U.S. and international pension plans, respectively, during 2006. Through September 30, 2006, a total of $220 million was contributed, including approximately $100 million to the U.S. plans. Estimated contributions for the full year continue to be $500 million, but 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 2006, the company contributed $160 million to its other postretirement benefit plans. The company anticipates contributing an additional $60 million during the remainder of 2006.

16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 11. 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 Position FAS 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, 2006, was approximately $1.2 billion, an increase of $130 million from year-end 2005 due mainly to drilling activity in the United States. For the category of exploratory well costs at year-end 2005 that were suspended more than one year, a total of $70 million was expensed in the first nine months of 2006.

Note 12. Asset Retirement Obligations

      As of September 30, 2006, the company’s liability for asset retirement obligations calculated in accordance with FASB Statement No. 143,“Accounting for Asset Retirement Obligations,”was approximately $5.4 billion, compared with $4.3 billion at year-end 2005. The $1.1 billion increase included approximately $800 million associated with estimated costs to dismantle and abandon wells and facilities damaged by last year’s hurricanes in the Gulf of Mexico. The offset to the $800 million increase in the abandonment liability was recorded to operating expense in the second quarter, net of approximately $400 million recoverable under the company’s insurance policies.

Note 13. Litigation

      Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. Chevron is a party to more than 70 lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners, related to the use of MTBE in certain oxygenated gasolines and the alleged seepage of MTBE into groundwater. Resolution of these actions may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future.

      The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company currently does not use MTBE in the manufacture of gasoline in the United States.

Note 14. Other Contingencies and Commitments

     Income Taxes The U.S. federal income tax liabilities have been settled through 1996 for Chevron Corporation (formerly ChevronTexaco Corporation) and 1997 for Chevron Global Energy Inc. (formerly Caltex Corporation), and Unocal Corporation (Unocal), and through 1991 for Texaco Inc. (Texaco). California franchise tax liabilities have been settled through 1991 for Chevron, 1998 for Unocal and through 1987 for Texaco.

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

     Guarantees The company and its subsidiaries have certain other contingent liabilities with respect to guarantees, direct or indirect, of debt of affiliated companies or others and long-term unconditional purchase obligations and commitments, throughput agreements and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. Under the terms of the guarantee arrangements, generally the company would be required to perform should the affiliated company or third party fail to fulfill its obligations under the

17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

arrangements. In some cases, the guarantee arrangements have recourse provisions that would enable the company to recover any payments made under the terms of the guarantees from assets provided as collateral.

     Off-Balance-Sheet Obligations The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, throughput agreements, and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, 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 Oil Company (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 maximum future payments up to $300 million. Through September 30, 2006, 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 interests in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims relating to Equilon indemnities must be asserted either as early as February 2007, or no later than February 2009, and claims relating to Motiva must be asserted no later than February 2012. Under the terms of 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 these indemnities.

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

      In the acquisition of Unocal, the company assumed certain indemnities for contingent environmental liabilities associated with Unocal’s 76 Products Company business that was sold in 1997. Under the indemnification agreement, the company’s liability is unlimited until April 2022, when the liability expires. The acquirer shares in certain environmental remediation costs up to a maximum obligation of $200 million, which had not been incurred as of September 30, 2006.

     Minority Interests The company has commitments of $227 million related to minority interests in subsidiary companies.

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

18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

     Global Operations Chevron and its affiliates conduct business activities in approximately 180 countries. Areas in which the company and its affiliates have significant operations or ownership interests include the United States, Canada, Australia, the United Kingdom, Norway, Denmark, France, the Netherlands, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, Republic of the Congo, Angola, Nigeria, Chad, South Africa, Democratic Republic of the Congo, Indonesia, India, Bangladesh, the Philippines, Myanmar, Singapore, China, Thailand, Vietnam, Cambodia, Azerbaijan, Kazakhstan, Venezuela, Argentina, Brazil, Colombia, Trinidad and Tobago and South Korea. The company’s Caspian Pipeline Consortium (CPC) affiliate operates in Russia and Kazakhstan. The company’s Tengizchevroil (TCO) affiliate operates in Kazakhstan. Through an affiliate, the company participates in the operation of the Baku-Tbilisi-Ceyhan (BTC) pipeline through Azerbaijan, Georgia and Turkey. Also through an affiliate, the company has an interest in the Chad/ Cameroon pipeline. The company’s Petrolera Ameriven affiliate operates the Hamaca project in Venezuela. The company’s Chevron Phillips Chemical Company LLC (CPChem) affiliate manufactures and markets a wide range of petrochemicals on a worldwide basis, with manufacturing facilities in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar and Belgium. The company’s GS Caltex affiliate manufactures and markets refined products and petrochemicals in South Korea.

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

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

     Equity Redetermination For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude oil and natural gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for Chevron’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills in California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. 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.

19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 15. New Accounting Standards

     EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (Issue 04-13). The company adopted the accounting prescribed by Issue 04-13 on a prospective basis from April 1, 2006. Issue 04-13 requires that two or more legally separate exchange transactions with the same counterparty, including buy/sell transactions, be combined and considered as a single arrangement for purposes of applying the provisions of Accounting Principles Board Opinion No. 29,“Accounting for Nonmonetary Transactions,” when the transactions are entered into “in contemplation” of one another. In prior periods, the company accounted for buy/sell transactions in the Consolidated Statement of Income the same as a monetary transaction — purchases were reported as “Purchased crude oil and products”; sales were reported as “Sales and other operating revenues.”

      With the company’s adoption of Issue 04-13, buy/sell transactions from April 1, 2006, are netted against each other on the Consolidated Statement of Income, with no effect on net income. Amounts associated with buy/sell transactions in periods prior to the second quarter 2006 are shown as a footnote to the Consolidated Statement of Income on page 3.

     EITF Issue No. 06-3, “How Sales Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross Versus Net Presentation)” (Issue 06-3). In September 2006, the FASB ratified the earlier EITF consensus on Issue 06-3, which will become effective for the company on January 1, 2007. The new accounting standard requires that a company disclose its policy for recording taxes assessed by a governmental authority on a revenue-producing transaction between a seller and a customer. In addition, for any such taxes that are reported on a gross basis, a company is required to disclose the amounts of those taxes. The company’s policy in relation to Issue 06-3 has been to present the relevant taxes on a gross basis. The associated amounts are shown as a footnote to the Consolidated Statement of Income on page 3.

     FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109”(FIN 48). In July 2006, the FASB issued FIN 48, which will become effective for the company on January 1, 2007. This standard clarifies the accounting for income tax benefits that are uncertain in nature. Under FIN 48, a company will recognize a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that its position is “more likely than not” (i.e., a greater than 50 percent likelihood) to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies. Under the transition guidance for implementing FIN 48, any required cumulative-effect adjustment will be recorded to retained earnings as of January 1, 2007. The company does not expect implementation of the standard will have a material effect on its results of operations or financial position.

     FASB Statement No. 157, “Fair Value Measurements”(FAS 157). In September 2006, the FASB issued FAS 157, which will become effective for the company on January 1, 2008. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to the company from the adoption of FAS 157 in 2008 will depend on the company’s assets and liabilities at that time that are required to be measured at fair value.

     FASB Statement No. 158,“Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106 and 132(R)”(FAS 158). In September 2006, the FASB issued FAS 158, which will become effective for the company on December 31, 2006. This standard requires the company to recognize the overfunded or underfunded status of each of its defined benefit pension and other postretirement benefit (OPEB) plans as an asset or liability and to reflect changes in the

20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

funded status through “Accumulated other comprehensive income,” as a separate component of stockholders’ equity, in the year in which they occur.

      Based on estimates as of September 30, 2006, the company anticipates total assets and stockholders’ equity upon adoption of FAS 158 will be reduced by $2.5 billion. This estimate will differ from the actual impacts at December 31, 2006, which will be based on year-end pension plan asset valuations and calculations of the company’s obligations as of year-end for pensions and other postretirement benefit plans.

     FASB Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities.” In September 2006, the FASB issued Staff Position No. AUG AIR-1, which will become effective for the company on January 1, 2007. The Staff Position prohibits companies from recognizing planned major maintenance cost by accruing a liability over several reporting periods before the maintenance is performed or over interim-reporting periods within the annual period in which the cost is expected to be incurred. The company does not expect the standard will have any effect on its results of operations or financial position, as expenditures for routine and major maintenance projects, repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized.

      In September 2006, the SEC staff also issued Staff Accounting Bulletin No. 108,“Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB 108). While not an official rule or interpretation of the SEC, SAB 108 was issued to address the diversity in practice in quantifying misstatements from prior years and assessing their effect on current year financial statements. The company does not anticipate any impact to the preparation of its year-end 2006 financial statements from adopting the guidance of SAB 108.

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

Third Quarter 2006 Compared with Third Quarter 2005

and Nine Months 2006 Compared with Nine Months 2005

Key Financial Results

Income by Business Segments

		Three Months Ended						Nine Months Ended
		September 30						September 30
		2006			2005			2006			2005
		(Millions of dollars)
Income by Business Segment
Upstream — Exploration and Production
	United States	$	1,269		$	1,206		$	3,384		$	2,945
	International		2,234			2,117			6,849			5,529
Total Upstream			3,503			3,323			10,233			8,474
Downstream — Refining, Marketing and Transportation
	United States		831			139			1,595			595
	International		610			434			1,424			1,363
Total Downstream			1,441			573			3,019			1,958
Chemicals			168			6			415			227
Total Segment Income			5,112			3,902			13,667			10,659
All Other			(95	)		(308	)		(301	)		(704	)
Net Income*		$	5,017		$	3,594		$	13,366		$	9,955
* Includes foreign currency effects		$	(111	)	$	(52	)	$	(275	)	$	(19	)

     Net incomefor the 2006 third quarter was $5.0 billion ($2.29 per share — diluted), compared with $3.6 billion ($1.64 per share — diluted) in the 2005 third quarter. Net income for the first nine months of 2006 was $13.4 billion ($6.06 per share — diluted), vs. $10.0 billion ($4.68 per share — diluted) in the corresponding 2005 period. In the following discussion, the term “earnings” is defined as segment income.

     Upstreamearnings in the third quarter 2006 were $3.5 billion, compared with $3.3 billion in the year-ago period. Earnings for the first nine months of 2006 were $10.2 billion, vs. $8.5 billion a year earlier. Results for both 2006 periods benefited from higher prices for crude oil and an increase in oil-equivalent production that was associated with the acquisition of Unocal in August 2005. (Refer to Note 2 on page 7 for a discussion of the Unocal acquisition.)

     Downstreamearnings were $1.4 billion in the third quarter 2006, up from $0.6 billion a year earlier. Nine-month 2006 earnings were $3.0 billion, vs. $2.0 billion in the corresponding 2005 period. The earnings improvement in both periods was driven mainly by increased refinery utilization and improved refined-product margins in the United States.

     Chemicalsearnings were $168 million, up from $6 million in the 2005 third quarter. Earnings for the nine months of 2006 were $415 million, up from $227 million a year earlier.

      Refer to pages 26 - 29 for additional discussion of earnings by business segment for the third quarter and nine months of 2006.

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Business Environment and Outlook

      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 chemical business and other activities and investments. Earnings for the company in any period may also be influenced by events or transactions that are infrequent and/or unusual in nature. Chevron and the oil and gas industry at large are currently experiencing an increase in certain costs that exceeds the general trend of inflation in many areas of the world. This increase in cost is affecting the company’s operating expenses for all business segments and capital expenditures, particularly for the upstream business.

      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. Changes in economic, legal or political circumstances can have significant effects on the profitability of a project over its expected life. In the current environment of higher commodity prices, certain governments have sought to renegotiate contracts or impose additional costs 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 continuously 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. Asset dispositions and restructurings may occur in future periods and could result in significant gains or losses.

      Comments related to the trend in earnings 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 damages and disruptions, competing fuel prices, and regional supply interruptions that may be caused by military conflicts, civil unrest or political uncertainty. Moreover, any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments, and attempts to manage risks in operating its facilities and business.

      During 2005, industry price levels for West Texas Intermediate (WTI), a benchmark crude oil, averaged $57 per barrel. Prices trended upward in the first nine months of 2006, with WTI averaging over $70 per barrel for the third quarter and $68 for the nine months. The benchmark price declined during October 2006, averaging $59 per barrel for the month. Among the factors contributing to the decline in prices during October were ample output and inventories of crude oil and refined products worldwide. The improved supply and demand balance was due in part to a relatively quiet storm season in the U.S. Gulf of Mexico this year, enabling oil and gas production and refineries to operate with significantly less downtime than a year ago.

      During 2005 and the first nine months of 2006, a wide differential in price existed between high quality, light-sweet crude oils (such as the U.S. benchmark WTI) and heavier types of crude. The price for heavier crudes has been dampened because of ample supply and lower relative demand due to the limited number of refineries that are able to process this lower-quality feedstock into light products (i.e., motor gasoline, jet fuel, aviation gasoline and diesel fuel). The price for the higher-quality light-sweet crude oil, on the other hand, has remained high, as the demand for light products, which can be more easily manufactured by refineries from

23

light-sweet crude oil, has been strong worldwide. Chevron produces 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 prices.)

      U.S. benchmark prices for Henry Hub natural gas averaged $6.40 per thousand cubic feet (MCF) in the first nine months of 2006, compared with about $7.50 for the corresponding 2005 period. The Henry Hub price for October 2006 averaged $5.40 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 inventory in underground storage relative to customer demand. Natural gas prices in the United States are also typically higher during the winter period, when demand for heating is greatest.

      In contrast to the United States, certain other regions of the world in which the company operates have different supply, demand and regulatory circumstances for natural gas, typically resulting in significantly lower average sales prices for the company’s production. (Refer to page 32 for the company’s average natural gas prices for the U.S. and international regions.) Additionally, excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the United States and other markets because of the lack of infrastructure and the difficulties in transporting natural gas.

      To help address this regional imbalance between supply and demand for natural gas, Chevron is planning increased investments in long-term projects in areas of excess supply to install infrastructure to produce and liquefy natural 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 price for crude oil and natural gas, the longer-term trend in earnings for the upstream segment is also a function of other factors, including changes in the company’s crude oil and natural gas production levels, changes in fiscal terms, the cost of goods and services, and the company’s ability to find or acquire and efficiently produce crude oil and natural gas reserves.

      With regard to the company’s level of net oil-equivalent production, approximately 25 percent of the company’s production in the first nine months of 2006 occurred in the OPEC-member countries of Indonesia, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. The company’s production level during the first nine months of 2006 was not constrained in these areas by OPEC quotas. On October 20, 2006 OPEC announced its decision to reduce OPEC-member production quotas by 1.2 million barrels of crude oil per day from current production level of 27.5 million barrels per day (4.4 percent), effective November 1, 2006. The effect of this action, if any, on the company’s future production is uncertain.

      In 2005, the Venezuelan government stipulated that Chevron’s Boscan and LL-652 operating service agreements be converted to Empresas Mixtas (i.e., joint stock contractual structures), with Petróleos de Venezuela, S.A. (PDVSA) as majority shareholder. Chevron signed definitive agreements for the contract conversions in July 2006, but the formation of the two Empresa Mixta companies was delayed and they did not become effective until October 9, 2006. From that date, Chevron will report its equity share of the Boscan and LL-652 production, which is expected to be approximately 90,000 barrels per day less than what the company previously reported under the operating service agreements. The financial implications of the Empresa Mixta structure are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.

      In certain onshore areas of Nigeria, approximately 30,000 barrels per day of the company’s net production capacity remain shut in because of civil unrest and damages to facilities that occurred in 2003. The company has adopted a phased plan to restore this capacity as conditions permit.

24

      In the first nine months of 2006, the company’s worldwide oil-equivalent production averaged 2.67 million barrels per day, including the volumes produced from oil sands in Canada and the production associated with the operating service agreements in Venezuela. Beyond the known reduction of 90,000 barrels per day associated with the Empresa Mixta conversions in Venezuela, any estimate of future production is subject to many uncertainties, including quotas that may be imposed by OPEC, the price effect on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, and production disruptions that could be caused by severe weather, local civil unrest and changing geopolitics. Future production levels also are 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. Most of Chevron’s upstream investment is currently being made outside the United States. Investments in upstream projects generally are made well in advance of the start of the associated crude oil and natural gas production.

      Refer also to the Results of Operations on pages 26 - 27 for additional discussion of U.S. and international production trends.

     Downstream Earnings for the downstream segment are closely tied to global and regional supply and demand for refined products and the associated effects on industry refining and marketing margins. The company’s core marketing areas are the West Coast of North America, the U.S. Gulf Coast, Latin America, Asia and sub-Saharan Africa. Earnings improved during the first nine months of 2006, mainly as the result of higher average margins for refined products and improved operations at the company’s refineries. Industry margins in the future may be volatile, due primarily to changes in the price of crude oil used for refinery feedstock, disruptions at refineries resulting from maintenance programs and unplanned outages, and levels of inventory and demand for refined products.

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

      Refer also to the Results of Operations on pages 27 - 28 for additional discussion of downstream earnings.

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

      Refer also to the Results of Operations on page 28 for additional discussion of chemical earnings.

Operating Developments

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

•  United States — Completion of a record setting production test on the 50 percent-owned and operated Jack #2 well, located 175 miles offshore southwest of New Orleans in the U.S. Gulf of Mexico. The production test is afollow-up to the 2004 Jack discovery in Walker Ridge Block 758. The production well test in 7,000 feet of water and 20,000 feet under the sea floor is the deepest ever accomplished in the Gulf of Mexico.

•  United States — Decision to develop the Great White, Tobago and Silvertip fields located in the U.S. Gulf of Mexico. The fields are expected to use a common producing hub, the Perdido Regional Host, with a capacity of 130,000 barrels of oil-equivalent per day. First production from the 37.5 percent-owned Perdido Regional Host is anticipated in 2010. Chevron’s ownership interests in the fields are Great White — 33.3 percent, Tobago — 57.5 percent and Silvertip — 60 percent.

•  Canada — Decision to participate in the expansion of the Athabasca Oil Sands Project (AOSP) in Alberta, Canada. The expansion is expected to add 100,000 barrels per day of mining and upgrading

25

capacity at an estimated cost of $10 billion. Completion of the expansion is planned for 2010, increasing total capacity of the project to approximately 255,000 barrels of oil per day. Chevron holds a 20 percent nonoperated interest in AOSP.

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 4 beginning on page 9 for a discussion of the company’s “reportable segments,” as defined in FAS 131,“Disclosures about Segments of an Enterprise and Related Information.”)

Upstream

	Three Months				Nine Months
	Ended				Ended
	September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
U.S. Upstream Income	$	1,269	$	1,206	$	3,384	$	2,945

      U.S. upstream income of $1.27 billion in the third quarter 2006 was up 5 percent from the year earlier. Earnings between periods benefited by about $100 million due to the net effect of higher prices for crude oil and natural gas liquids and lower prices for natural gas. Third-quarter 2006 earnings also benefited from a 5 percent increase in oil-equivalent production and a reduction in uninsured expenses associated with hurricanes in the Gulf of Mexico in 2005. Partially offsetting these contributions to earnings were the effects of higher operating expenses and an increase in expense for the depreciation of wells, equipment and facilities.

      Nine-month 2006 earnings were approximately $3.4 billion, up 15 percent from the same period in 2005. Higher average prices for crude oil increased earnings about $900 million between periods. Also benefiting earnings was a 4 percent increase in oil-equivalent production. Partially offsetting these benefits between periods were the effects of lower natural gas prices and higher operating expenses, including hurricane-related charges.

      The average liquids realization in the third quarter was $61.99 per barrel, up from $53.00. For the comparable nine-month period, the average realization of $58.58 was up 29 percent from $45.30. The average natural gas realization for the third quarter 2006 was $5.93 per thousand cubic feet, down from $7.34 in the 2005 quarter. For the nine months, the average realization was $6.41, down marginally from $6.49 in 2005.

      Net oil-equivalent production was 772,000 barrels per day in the third quarter 2006, up 5 percent from a year ago on volumes associated with the Unocal acquisition. Nine-month production increased 4 percent to 763,000 barrels per day. The increase for the nine-month period was less than the impact of the Unocal-related volumes due to adverse carryover effects on production from last year’s hurricanes. The net liquids component of oil-equivalent production was up 2 percent to 464,000 barrels per day for the quarter and relatively flat at 460,000 for the first nine months. Net natural gas production for the third quarter and first nine months of 2006 averaged 1.8 billion cubic feet per day, up 10 percent and 11 percent, respectively, from the year-ago periods.

	Three Months						Nine Months
	Ended						Ended
	September 30						September 30
	2006			2005			2006			2005
	(Millions of dollars)
International Upstream Income*	$	2,234		$	2,117		$	6,849		$	5,529
* Includes foreign currency effects	$	(100	)	$	(30	)	$	(319	)	$	9

26

      International upstream income of $2.23 billion in the third quarter 2006 increased $117 million from the 2005 period. Higher prices for crude oil and natural gas benefited earnings approximately $400 million. Also contributing to the earnings improvement was a 6 percent increase in oil-equivalent production. These benefits to earnings were largely offset by one-time charges for income taxes, including higher taxes on operations in the U.K. North Sea, and higher exploration and operating expenses. Foreign currency effects decreased earnings by $100 million in the third quarter 2006, compared with a decrease to earnings of $30 million in the year-ago period. These changes between periods were primarily due to the strengthening of the currencies of the United Kingdom and Thailand against the U.S. dollar.

      For the nine-month period, income was approximately $6.8 billion, up $1.3 billion from the corresponding 2005 period. Higher prices for crude oil and natural gas in 2006 benefited earnings about $1.7 billion. An increase in oil-equivalent production of 10 percent also contributed to the profit improvement. Partially offsetting these benefits were approximately $300 million of one-time charges for higher income tax rates and settlement of tax claims. Operating expenses were also higher in the first nine months of 2006. Foreign currency effects reduced earnings $319 million in the 2006 period, vs. a $9 million benefit to earnings in 2005. The change between periods was again due to strengthening of the United Kingdom and Thailand currencies.

      The average liquids realization for the third quarter 2006 was $61.90 per barrel, an increase of 14 percent from $54.26 in the 2005 period. For the first nine months of 2006, the average realization was $59.70, compared with $46.67 for the nine months of 2005. The average natural gas realization in the 2006 third quarter was $3.66 per thousand cubic feet, up from $3.13 in the third quarter last year. Between nine-month periods, the average natural gas realization increased 23 percent from a year ago to $3.75.

      Net oil-equivalent production for both the third quarter and first nine months of 2006 was 1.9 million barrels per day, up 6 percent and 10 percent, respectively, from the corresponding periods in 2005. The increase for both periods was mostly attributable to the Unocal acquisition. The third-quarter production increase also included higher output in Angola, Trinidad and Tobago and Kazakhstan, the effects of which were moderated by lower cost-oil recovery volumes in Indonesia and the Philippines and by the effects of maintenance activities in Venezuela and Denmark. The nine-month production increase included the higher volumes in Angola and Trinidad and Tobago, which were partially offset by lower cost-oil recovery in Indonesia and the Philippines and by maintenance work in 2006 on facilities in Canada at the Athabasca oil sands operation and at the Captain Field in the United Kingdom. The net liquids component of oil-equivalent production for the third quarter 2006 was 1.3 million barrels per day and essentially the same for the nine-month period. Production for the quarter and nine months was approximately 5 percent higher than in the corresponding periods of 2005. Net natural gas production was 3.1 billion cubic feet per day for the 2006 quarter and 3.2 billion for the nine-months, up 12 percent and 34 percent from the year-ago periods, respectively.

Downstream

	Three Months				Nine Months
	Ended				Ended
	September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
U.S. Downstream Income	$	831	$	139	$	1,595	$	595

      U.S. downstream earnings of $831 million increased $692 million from the 2005 third quarter. For the first nine months of 2006, earnings were about $1.6 billion, compared with $595 million in the corresponding 2005 period. Earnings for both comparative periods increased primarily as a result of higher refined-product margins and improved refinery utilization.

      Crude oil inputs at the company’s refineries in the third quarter of 2006 were 967,000 barrels per day, up 34 percent from the year-ago period. Crude oil inputs of 947,000 barrels per day for the nine months increased 14 percent from the same period in 2005. The improved utilization was associated mainly with downtime

27

during 2005 for maintenance and repairs, including an extended outage in the third quarter 2005 at the company’s refinery in Pascagoula, Mississippi, due to hurricane damage.

      Refined-product sales volumes in the third quarter 2006 increased 2 percent from a year earlier to 1,502,000 barrels per day. The reported sales volume for 2006 was on a different basis than in 2005 due to a change in accounting rules that became effective April 1, 2006, for certain purchase and sale contracts with the same counterparty. (Refer to the discussion of “New Accounting Standards” on page 20.) Prior to the accounting change, transactions for these types of contracts were reported separately as a purchase and a sale. The new accounting standard requires the transactions to be netted. Excluding the impact of this new accounting standard, sales of refined products were about 9 percent higher in the 2006 quarter, primarily the result of higher refinery output. On the same adjusted basis for the nine-month period, sales were approximately 5 percent higher in 2006. Branded gasoline sales increased 3 percent from last year’s third quarter and nine-month period, respectively.

	Three Months						Nine Months
	Ended						Ended
	September 30						September 30
	2006			2005			2006		2005
	(Millions of dollars)
International Downstream Income*	$	610		$	434		$	1,424	$	1,363
* Includes foreign currency effects	$	(21	)	$	(22	)	$	2	$	2

      International downstream income of $610 million increased $176 million from the third quarter 2005. Earnings for the nine months of 2006 were $1.4 billion, up $61 million from the 2005 period. The increase in both periods was associated mainly with the benefit of higher refined-product margins in the Asia-Pacific region and improved results from crude oil and refined product trading activities.

      The company’s share of refinery crude-oil inputs was 1,055,000 barrels per day for the third quarter 2006, down 3 percent from the year earlier. For the nine months, inputs were 3 percent higher at 1,067,000 barrels per day. Total refined-product sales volumes were 2,148,000 barrels per day in the 2006 third quarter and 2,160,000 for the nine months, down 1 percent and 4 percent, respectively, from the year-ago periods. After adjusting for the effect of the new accounting standard for purchase and sale contracts, refined-product sales were higher by 5 percent and 1 percent for the respective comparative periods. The increase for the third quarter was primarily associated with sales of jet fuel and gas oils in East Africa and the Middle East.

Chemicals

	Three Months				Nine Months
	Ended				Ended
	September 30				September 30
	2006		2005		2006			2005
	(Millions of dollars)
Income*	$	168	$	6	$	415		$	227
* Includes foreign currency effects	$	4	$	2	$	(7	)	$	—

      Chemical operations earned $168 million in the third quarter 2006, compared with $6 million in the 2005 period. For the nine months, earnings increased $188 million from a year ago to $415 million. Earnings for the 50 percent-owned Chevron Phillips Chemical Company LLC and the company’s Oronite subsidiary were both adversely affected in the 2005 third quarter by disruptions and damages caused by hurricanes in the Gulf of Mexico. Margins for commodity chemicals and fuel and lubricant additives improved between the comparative periods.

28

All Other

	Three Months						Nine Months
	Ended						Ended
	September 30						September 30
	2006			2005			2006			2005
	(Millions of dollars)
Net Charges*	$	(95	)	$	(308	)	$	(301	)	$	(704	)
* Includes foreign currency effects	$	6		$	(2	)	$	49		$	(30	)

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

      Net charges were $95 million in the third quarter 2006, compared with $308 million in the corresponding 2005 period. Net charges for the first nine months of 2006 were $301 million, vs. $704 million in 2005. The reduction in net charges for the quarter related mainly to lower expenses for environmental and litigation matters, higher interest income net of interest expense, and lower expenses for income taxes and other corporate items. The loweryear-to-date charges in 2006 were also associated with a gain on the redemption of an investment in Dynegy preferred stock, interest income net of interest expense and a gain on the retirement of $1.5 billion of Unocal debt. Foreign currency effects also contributed to the reduction in net charges for both comparative periods, although more significantly for the nine-months.

Consolidated Statement of Income

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

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
Sales and other operating revenues*	$	52,977	$	53,429	$	158,654	$	141,184
* Includes amount for buy/sell contracts	$	—	$	6,588	$	6,725	$	17,925

      Sales and other operating revenues in both periods benefited from increased production of crude oil and higher prices for crude oil and refined products. For the quarterly period, these effects were more than offset by the impact of the accounting-standard change beginning April 1 for certain purchase and sale contracts with the same counterparty.

	Three Months				Nine Months
	Ended				Ended
	September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
Income from equity affiliates	$	1,080	$	871	$	3,176	$	2,621

      The increase in income from equity affiliates in both periods reflected improved results for Chevron Phillips Chemical Company and Tengizchevroil in Kazakhstan, which were partially offset by lower earnings at the Hamaca project in Venezuela. The nine months also included an improvement in Dynegy-related earnings.

	Three Months				Nine Months
	Ended				Ended
	September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
Other income	$	155	$	156	$	542	$	601

29

      Other income was unchanged between the quarterly periods. Reduced income for the nine months was primarily due to foreign currency effects and the absence of a net gain from the sale of a Canadian upstream equity investment in 2005. These effects were partially offset in 2006 by higher interest income and a net gain on the early retirement of the Unocal debt.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
Purchased crude oil and products	$	32,076	$	36,101	$	100,493	$	93,722

      Purchased crude oil and products for the quarterly and nine-month 2006 periods increased on higher prices for crude oil and refined products. More than offsetting the increase for the quarterly period was the impact of the accounting-standard change beginning April 1 for certain purchase and sale contracts with the same counterparty.

	Three Months				Nine Months Ended
	Ended September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
Operating, selling, general and administrative expenses	$	5,078	$	4,527	$	14,422	$	11,860

      Operating, selling, general and administrative expenses in the third quarter and nine months of 2006 increased 12 percent and 22 percent, respectively, from the year-ago periods. Expenses associated with the acquisition of Unocal are included for nine months in 2006 vs. two months in 2005. Besides this effect, an increase in labor and transportation expense for the quarterly period was partially offset by lower uninsured costs associated with the storms in the Gulf of Mexico last year. For the nine months of 2006, expenses were higher for labor, transportation, fuel and uninsured costs associated with the storms in 2005.

	Three Months				Nine Months
	Ended				Ended
	September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
Exploration expenses	$	284	$	177	$	817	$	469

      Exploration expenses in the 2006 periods increased mainly due to higher amounts for well write-offs and geological and geophysical costs for operations outside the United States and the inclusion of expenses for the former Unocal operations for nine months in 2006 vs. two months in 2005.

	Three Months				Nine Months
	Ended				Ended
	September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
Depreciation, depletion and amortization	$	1,923	$	1,534	$	5,518	$	4,188

      The increase in depreciation, depletion and amortization in both comparative periods was mainly attributable to the inclusion of Unocal-related amounts.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
Taxes other than on income	$	5,403	$	5,282	$	15,350	$	15,719

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      Taxes other than on income increased in the third quarter 2006 mainly due to higher U.S. refined product sales. For theyear-to-date period, taxes decreased, primarily due to lower sales volumes subject to duties in the company’s European downstream operations.

	Three Months				Nine Months
	Ended				Ended
	September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
Interest and debt expense	$	104	$	136	$	359	$	347

      Interest and debt expense in the third quarter 2006 decreased primarily due to lower average debt balances, partially offset by higher interest rates on variable-rate debt. For the nine-month period, the increase was primarily the result of higher average interest rates on variable-rate debt.

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2006		2005		2006		2005
	(Millions of dollars)
Income tax expense	$	4,307	$	3,081	$	11,979	$	8,083

      Effective income tax rates for the third quarters of 2006 and 2005 were both 46 percent. For theyear-to-date periods, the effective tax rates were 47 percent and 45 percent, respectively. The higher tax rate in the 2006 nine-month period included the effect of one-time charges totaling $300 million, including an increase in tax rates on upstream operations in the U.K. North Sea.

Information Relating to the Company’s Investment in Dynegy

      Chevron owns an approximate 20 percent equity interest in the common stock of Dynegy Inc. (Dynegy), a provider of electricity to markets and customers throughout the United States.

     Investment in Dynegy Common StockAt September 30, 2006, the carrying value of the company’s investment in Dynegy common stock was $260 million. This amount was about $203 million below the company’s proportionate interest in Dynegy’s underlying net assets. This difference is primarily the result of write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value that were determined to be other than temporary. The difference was assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors associated with the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly when appropriate to recognize a portion of the difference between these allocated values and Dynegy’s historical book values. The market value of the company’s investment in Dynegy’s common stock at September 30, 2006, was $537 million.

     Investment in Dynegy Preferred StockIn May 2006, the company’s investment in Dynegy Series C preferred stock was redeemed at its face value of $400 million. Upon redemption of the preferred stock, the company recorded a gain of $130 million, of which $105 million was reclassified from “Other Comprehensive Income.”

     Dynegy Proposed Business Combination with LS Power GroupDynegy and LS Power Group, a privately held power plant investor, developer and manager, announced on September 15, 2006, the companies had executed a definitive agreement to combine Dynegy’s assets and operations with LS Power Group’s power-generation portfolio, and for Dynegy to acquire a 50 percent ownership interest in a development joint venture with LS Power. Upon close of the transaction, Chevron will receive the same number of shares of the new company’s Class A common stock that it currently holds in Dynegy. Chevron’s ownership interest in the combined company will be approximately 11 percent. The transaction is subject to specified conditions, including the affirmative vote of two-thirds of Dynegy’s public shareholders and the receipt of regulatory approvals.

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Selected Operating Data

      The following table presents a comparison of selected operating data:

Selected Operating Data(1)(2)

			Three Months				Nine Months
			Ended				Ended
			September 30				September 30
			2006		2005		2006		2005
U.S. Upstream
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			464		455		460		459
	Net Natural Gas Production (MMCFPD)(3)			1,846		1,676		1,820		1,633
	Net Oil-Equivalent Production (MBOEPD)			772		735		763		731
	Sales of Natural Gas (MMCFPD)			7,851		5,795		7,077		5,474
	Sales of Natural Gas Liquids (MBPD)			125		170		121		170
	Revenue from Net Production
		Liquids ($/Bbl.)	$	61.99	$	53.00	$	58.58	$	45.30
		Natural Gas ($/MCF)	$	5.93	$	7.34	$	6.41	$	6.49
International Upstream
	Net Crude Oil and Natural Gas Liquids Production (MBPD)			1,267		1,206		1,245		1,193
	Net Natural Gas Production (MMCFPD)(3)			3,119		2,785		3,172		2,366
	Net Oil-Equivalent Production (MBOEPD)(5)			1,928		1,813		1,908		1,729
	Sales of Natural Gas (MMCFPD)(4)			3,367		2,689		3,443		2,247
	Sales of Natural Gas Liquids (MBPD)(4)			105		124		101		116
	Revenue from Liftings
		Liquids ($/Bbl.)	$	61.90	$	54.26	$	59.70	$	46.67
		Natural Gas ($/MCF)	$	3.66	$	3.13	$	3.75	$	3.04
U.S. and International Upstream
	Total Net Oil-Equivalent Production, including Other Produced Volumes (MBOEPD)(3)(5)			2,700		2,548		2,671		2,460
U.S. Downstream
	Gasoline Sales (MBPD)(6)			720		745		718		719
	Other Refined Products Sales (MBPD)			782		733		783		764
		Total(7)		1,502		1,478		1,501		1,483
	Refinery Input (MBPD)			967		719		947		828
International Downstream
	Gasoline Sales (MBPD)(4)(6)			472		524		490		546
	Other Refined Products Sales (MBPD)(4)			1,138		1,150		1,163		1,209
	Share of Affiliate Sales (MBPD)(4)			538		502		507		491
		Total(4)(7)		2,148		2,176		2,160		2,246
	Refinery Input (MBPD)			1,055		1,088		1,067		1,036

(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 on lease (MMCFPD):(4)
United States		71	52	53	54
International		408	370	391	335
(4)  2005 conformed to 2006 presentation
(5)  Includes other produced volumes (MBPD):
Athabasca oil sands — net		33	33	25	31
Boscan Operating Service Agreement		108	111	109	111
	Total	141	144	134	142
(6)  Includes branded and unbranded gasoline.
(7)  Includes volumes for buy/sell contracts (MBPD):
United States		—	104	35	89
International		—	129	32	135

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Liquidity and Capital Resources

     Cash and cash equivalents and marketable securitiestotaled $12.3 billion at September 30, 2006, up $1.1 billion from year-end 2005. Cash provided by operating activities in the first nine months of 2006 was $18.6 billion, an amount sufficient for the company’s capital and exploratory program, payment of dividends to stockholders, repayment of debt and repurchase of common stock.

     DividendsThe company paid dividends of $3.3 billion to common stockholders during the first nine months of 2006.

     Debt and Capital Lease and Minority Interest ObligationsChevron’s total debt and capital lease obligations were $10.4 billion at September 30, 2006, vs. $12.9 billion at December 31, 2005. The company also had minority interest obligations of $227 million at September 30, 2006. In the first quarter of 2006, $185 million of Unocal bonds were retired at maturity. In the second quarter, the company redeemed approximately $1.7 billion of Unocal debt and recognized a $92 million before-tax gain. In October 2006, a $129 million Texaco Capital Inc. bond matured. Also in October, the company issued notices to call Union Oil Company bonds with face value of $156 million. These bonds are expected to be retired in November 2006.

      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 $6.9 billion at September 30, 2006, up from $5.6 billion at December 31, 2005. Of these amounts, $4.6 billion and $4.8 billion were reclassified to long-term at September 30, 2006, and December 31, 2005, respectively. At September 30, 2006, 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. The company’s practice has been to continually refinance its commercial paper, maintaining levels it believes appropriate and economic.

      At September 30, 2006, the company had $5.0 billion in committed credit facilities with various major banks, which permitted the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and also can be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on 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, 2006. In addition, the company has three existing effective “shelf” registrations on file with the Securities and Exchange Commission that together would permit additional registered debt offerings up to an aggregate $3.8 billion of debt securities.

      Debt issued or guaranteed by Chevron Corporation is rated AA by Standard and Poor’s Corporation and Aa2 by Moody’s Investors Service. The bonds of Union Oil Company of California, an indirect wholly owned subsidiary of Chevron, are rated AA by Standard and Poor’s and A1 by Moody’s. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 by Moody’s, and the company’s Canadian commercial paper is rated R-1 (middle) by Dominion Bond Rating Service. All of these ratings denote high-quality, investment-grade securities.

      The company’s future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. Further reductions from debt balances at September 30, 2006, are dependent upon many factors including management’s continuous assessment of debt as an appropriate component of the company’s overall capital structure. The company believes it has substantial borrowing capacity to meet unanticipated cash requirements, and, during periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, the company believes that it has the flexibility to increase borrowings and/or modify capital spending plans to continue paying the common stock dividend and maintain the company’s high-quality debt ratings.

     Common Stock Repurchase ProgramIn December 2005, the company authorized the acquisition of up to $5 billion of its common shares from time to time at prevailing prices, as permitted by securities laws and

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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. During the third quarter 2006, 21.6 million shares were purchased in the open market at a cost of $1.4 billion. From the inception of the program in December 2005 through October 2006, the company had purchased 69 million shares for $4.2 billion. The company expects to complete the $5 billion stock buyback program by the end of 2006.

     Current Ratio — current assets divided by current liabilities. The current ratio was 1.3 at September 30, 2006, down from 1.4 at December 31, 2005. The current ratio is adversely affected by the valuation of Chevron’s inventories on a LIFO basis. At year-end 2005, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $4.8 billion. The company does not consider its inventory valuation methodology to affect liquidity.

     Debt Ratio — total debt as a percentage of total debt plus equity. This ratio was 13 percent at September 30, 2006, compared with 17 percent at year-end 2005.

     Pension ObligationsAt the end of 2005, the company estimated it would contribute $300 million and $200 million to its U.S. and international pension plans, respectively, during 2006. Through September 30, 2006, a total of $219 million was contributed, including approximately $100 million to the U.S. plans. Estimated contributions for the full year continue to be $500 million, but actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

     Capital and Exploratory ExpendituresTotal expenditures, including the company’s share of spending by affiliates, were $11.5 billion in the first nine months of 2006, compared with $7.1 billion, excluding the cost of the Unocal acquisition, in the corresponding 2005 period. The amounts included the company’s share of equity-affiliate expenditures of about $1.3 billion and $1.1 billion in the 2006 and 2005 periods, respectively. Expenditures for upstream projects in 2006 were about $9.0 billion, representing 78 percent of the companywide total.

Capital and Exploratory Expenditures by Major Operating Area

			Three Months Ended				Nine Months Ended
			September 30				September 30
			2006		2005		2006		2005
United States
	Upstream		$	1,036	$	692	$	3,007	$	1,616
	Downstream			279		272		723		505
	Chemicals			45		37		86		80
	All Other			113		85		267		223
		Total United States		1,473		1,086		4,083		2,424
International
	Upstream			2,272		1,524		5,963		3,853
	Downstream			363		280		1,402		761
	Chemicals			15		9		32		24
	All Other			5		8		7		25
		Total International		2,655		1,821		7,404		4,663
		Worldwide	$	4,128	$	2,907	$	11,487	$	7,087

Contingencies and Significant Litigation

     MTBEChevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. Chevron is a party to more than 70 lawsuits and claims, the majority of

34

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

      The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company currently does not use MTBE in the manufacture of gasoline in the United States.

     Income Taxes Income TaxesThe U.S. federal income tax liabilities have been settled through 1996 for Chevron Corporation (formerly ChevronTexaco Corporation) and 1997 for Chevron Global Energy Inc. (formerly Caltex Corporation), and Unocal Corporation (Unocal), and through 1991 for Texaco Inc. (Texaco). California franchise tax liabilities have been settled through 1991 for Chevron, 1998 for Unocal and through 1987 for Texaco.

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

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

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

     IndemnificationsThe company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell Oil Company (Shell) and Saudi Refining Inc. in connection with the February 2002 sale of the company’s interests in those investments. The company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make maximum future payments up to $300 million. Through September 30, 2006, 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 interests in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims relating to Equilon indemnities must be asserted either as early as February 2007, or no later than February 2009, and claims relating to Motiva must be asserted no later than February 2012. Under the terms of 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 these indemnities.

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

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      In the acquisition of Unocal, the company assumed certain indemnities for contingent environmental liabilities associated with Unocal’s 76 Products Company business that was sold in 1997. Under the indemnification agreement, the company’s liability is unlimited until April 2022, when the liability expires. The acquirer shares in certain environmental remediation costs up to a maximum obligation of $200 million, which had not been incurred as of September 30, 2006.

     Minority InterestsThe company has commitments of $227 million related to minority interests in subsidiary companies.

     EnvironmentalThe company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemical or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, 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.

     Global OperationsChevron and its affiliates conduct business activities in approximately 180 countries. Areas in which the company and its affiliates have significant operations or ownership interests include the United States, Canada, Australia, the United Kingdom, Norway, Denmark, France, the Netherlands, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, Republic of the Congo, Angola, Nigeria, Chad, South Africa, Democratic Republic of the Congo, Indonesia, India, Bangladesh, the Philippines, Myanmar, Singapore, China, Thailand, Vietnam, Cambodia, Azerbaijan, Kazakhstan, Venezuela, Argentina, Brazil, Colombia, Trinidad and Tobago and South Korea. The company’s Caspian Pipeline Consortium (CPC) affiliate operates in Russia and Kazakhstan. The company’s Tengizchevroil (TCO) affiliate operates in Kazakhstan. Through an affiliate, the company participates in the operation of the Baku-Tbilisi-Ceyhan (BTC) pipeline through Azerbaijan, Georgia and Turkey. Also through an affiliate, the company has an interest in the Chad/ Cameroon pipeline. The company’s Petrolera Ameriven affiliate operates the Hamaca project in Venezuela. The company’s Chevron Phillips Chemical Company LLC (CPChem) affiliate manufactures and markets a wide range of petrochemicals on a worldwide basis, with manufacturing facilities in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar and Belgium. The company’s GS Caltex affiliate manufactures and markets refined products and petrochemicals in South Korea.

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

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

     Equity RedeterminationFor oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude oil and natural gas reserves. These activities,

36

individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for Chevron’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills in California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. 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 ContingenciesChevron 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

     EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”(Issue 04-13). The company adopted the accounting prescribed by Issue 04-13 on a prospective basis from April 1, 2006. Issue 04-13 requires that two or more legally separate exchange transactions with the same counterparty, including buy/sell transactions, be combined and considered as a single arrangement for purposes of applying the provisions of Accounting Principles Board Opinion No. 29,“Accounting for Nonmonetary Transactions,” when the transactions are entered into “in contemplation” of one another. In prior periods, the company accounted for buy/sell transactions in the Consolidated Statement of Income the same as a monetary transaction — purchases were reported as “Purchased crude oil and products”; sales were reported as “Sales and other operating revenues.”

      With the company’s adoption of Issue 04-13, buy/sell transactions from April 1, 2006, are netted against each other on the Consolidated Statement of Income, with no effect on net income. Amounts associated with buy/sell transactions in periods prior to the second quarter 2006 are shown as a footnote to the Consolidated Statement of Income on page 3.

     EITF Issue No. 06-3, “How Sales Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross Versus Net Presentation)”(Issue 06-3). In September 2006, the FASB ratified the earlier EITF consensus on Issue 06-3, which will become effective for the company on January 1, 2007. The new accounting standard requires that a company disclose its policy for recording taxes assessed by a governmental authority on a revenue-producing transaction between a seller and a customer. In addition, for any such taxes that are reported on a gross basis, a company is required to disclose the amounts of those taxes. The company’s policy in relation to Issue 06-3 has been to present the relevant taxes on a gross basis. The associated amounts are shown as a footnote to the Consolidated Statement of Income on page 3.

     FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109”(FIN 48). In July 2006, the FASB issued FIN 48, which will become effective for the company on January 1, 2007. This standard clarifies the accounting for income tax benefits that are uncertain in nature. Under FIN 48, a company will recognize a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that its position is “more likely than not” (i.e., a greater than 50 percent likelihood) to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies. Under the transition guidance for implementing FIN 48, any required cumulative-effect adjustment will be recorded to retained earnings as of January 1, 2007. The company does not expect implementation of the standard will have a material effect on its results of operations or financial position.

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     FASB Statement No. 157, “Fair Value Measurements”(FAS 157). In September 2006, the FASB issued FAS 157, which will become effective for the company on January 1, 2008. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to the company from the adoption of FAS 157 in 2008 will depend on the company’s assets and liabilities at that time that are required to be measured at fair value.

     FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106 and 132(R)”(FAS 158). In September 2006, the FASB issued FAS 158, which will become effective for the company on December 31, 2006. This standard requires the company to recognize the overfunded or underfunded status of each of its defined benefit pension and other postretirement benefit (OPEB) plans as an asset or liability and to reflect changes in the funded status through “Accumulated other comprehensive income,” as a separate component of stockholders’ equity, in the year in which they occur.

      Based on estimates as of September 30, 2006, the company anticipates total assets and stockholders’ equity upon adoption of FAS 158 will be reduced by $2.5 billion. This estimate will differ from the actual impacts at December 31, 2006, which will be based on year-end pension plan asset valuations and calculations of the company’s obligations as of year-end for pensions and other postretirement benefit plans.

     FASB Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities.”In September 2006, the FASB issued Staff Position No. AUG AIR-1, which will become effective for the company on January 1, 2007. The Staff Position prohibits companies from recognizing planned major maintenance cost by accruing a liability over several reporting periods before the maintenance is performed or over interim-reporting periods within the annual period in which the cost is expected to be incurred. The company does not expect the standard will have any effect on its results of operations or financial position, as expenditures for routine and major maintenance projects, repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized.

      In September 2006, the SEC staff also issued Staff Accounting Bulletin No. 108,“Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB 108). While not an official rule or interpretation of the SEC, SAB 108 was issued to address the diversity in practice in quantifying misstatements from prior years and assessing their effect on current year financial statements. The company does not anticipate any impact to the preparation of its year-end 2006 financial statements from adopting the guidance of SAB 108.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

      Information about market risks for the three months ended September 30, 2006, does not differ materially from that discussed under Item 7A of Chevron’s Annual Report on Form 10-K for 2005.

Item 4. Controls and Procedures

      (a) Evaluation of disclosure controls and procedures

      Chevron Corporation’s Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the company’s “disclosure controls and procedures” (as defined in Rules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of September 30, 2006, have concluded that as of September 30, 2006, the company’s disclosure controls and procedures were effective and designed to provide reasonable assurance that material information relating to the company and its consolidated subsidiaries required to be included in the company’s periodic filings under the Exchange Act would be made known to them by others within those entities.

      (b) Changes in internal control over financial reporting

      During the quarter ended September 30, 2006, 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.

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

      Information about risk factors for the nine months ended September 30, 2006, does not differ materially from that set forth in Part I, Item 1A, of Chevron’s Annual Report on Form 10-K for 2005.

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

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, 2006		4,269,336		64.94		3,200,000		—
August 1-31, 2006		10,012,194		66.38		9,825,000		—
September 1-30, 2006		8,638,930		63.29		8,547,700		—
Total		22,920,460		64.94		21,572,700		(2	)

(1)

Includes 85,577 common shares repurchased during the three-month period ended September 30, 2006, 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 1,262,183 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, 2006.

(2)

In December 2005, the company authorized common stock repurchases of up to $5 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, 2006, $3.8 billion had been expended to repurchase 62,498,300 shares since the common stock repurchase program began.

Item 5. Other Information

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

      No change.

Rule 10b5-1 Plan Elections

      No rule 10b5-1 plans were adopted by executive officers or directors for the period that ended on September 30, 2006.

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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 company and its subsidiaries on a consolidated basis. A copy of any such instrument will be furnished to the Commission upon request
	(12	.1)	Computation of Ratio of Earnings to Fixed Charges
	(31	.1)	Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer
	(31	.2)	Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer
	(32	.1)	Section 1350 Certification by the company’s Chief Executive Officer
	(32	.2)	Section 1350 Certification by the company’s Chief Financial Officer

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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 3, 2006

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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 company and its subsidiaries on a consolidated basis. A copy of any such instrument will be furnished to the Commission upon request
(12.1)*	Computation of Ratio of Earnings to Fixed Charges
(31.1)*	Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer
(31.2)*	Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer
(32.1)*	Section 1350 Certification by the company’s Chief Executive Officer
(32.2)*	Section 1350 Certification by the company’s Chief Financial Officer

*  Filed herewith.

Copies of above exhibits not contained herein are available to any security holder upon written request to the Corporate Governance Department, Chevron Corporation, 6001 Bollinger Canyon Road, San Ramon, California 94583-2324.

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