Edgar Filing: CHEVRON CORP

Form 10-Q

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, 2011
or
¨		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-00368

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 (Zip Code)
(Address of principal executive offices)		94583-2324 (Zip Code)

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

NONE

(Former name, former address and former fiscal year, if changed since last report.)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer þ	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨
	(Do not check if a smaller reporting company)

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

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


Class		Outstanding as of September 30, 2011
Common stock, $.75 par value		1,991,484,388

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, 2011, and 2010		3
	Consolidated Statement of Comprehensive Income for the Three and Nine Months Ended September 30, 2011, and 2010		4
	Consolidated Balance Sheet at September 30, 2011, and December 31, 2010		5
	Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2011, and 2010		6
	Notes to Consolidated Financial Statements		7-22
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23-39
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		39
Item 4.	Controls and Procedures		39
PART II OTHER INFORMATION
Item 1.	Legal Proceedings		40-42
Item 1A.	Risk Factors		42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		43
Item 6.	Exhibits		44
Signature			45
Exhibits:	Computation of Ratio of Earnings to Fixed Charges		47
Rule 13a-14(a)/15d-14(a) Certifications			48-49
Section 1350 Certifications			50-51
Exhibit 12.1			47
Exhibit 31.1			48
Exhibit 31.2			49
Exhibit 32.1			50
Exhibit 32.2			51
Exhibit 99.1
Exhibit 101 Instance Document
Exhibit 101 Schema Document
Exhibit 101 Calculation Document
Exhibit 101 Definition Link Base Document
Exhibit 101 Labels Link Base Document
Exhibit 101 Presentation Link Base Document

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE

PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This quarterly report on Form 10-Q of Chevron Corporation contains forward-looking statements relating to Chevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “budgets” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond the company’s 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: changing crude oil and natural gas prices; changing refining, marketing and chemical margins; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company’s net production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or crude oil production quotas that might be imposed by the Organization of Petroleum Exporting Countries; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; the potential liability resulting from other pending or future litigation; the company’s future acquisition or disposition of assets and gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” on pages 32 through 34 of the company’s 2010 Annual Report on Form 10-K. In addition, such statements could be affected by general domestic and international economic and political conditions. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

PART I.

FINANCIAL INFORMATION

Item 1.

Consolidated Financial Statements

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF INCOME

(Unaudited)

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars, except per-share amounts)

Revenues and Other Income

Sales and other operating revenues*

$61,261

$48,554

$186,344

$146,346

Income from equity affiliates

2,227

1,242

5,796

4,127

Other income

944

(78

)

1,581

428

Total Revenues and Other Income

64,432

49,718

193,721

150,901

Costs and Other Deductions

Purchased crude oil and products

37,600

28,610

113,560

86,358

Operating expenses

5,378

4,665

15,701

13,845

Selling, general and administrative expenses

1,115

1,181

3,415

3,359

Exploration expenses

240

420

830

812

Depreciation, depletion and amortization

3,215

3,401

9,598

9,624

Taxes other than on income*

3,544

4,559

12,948

13,568

Interest and debt expense

—

Total Costs and Other Deductions

51,092

42,845

156,052

127,612

Income Before Income Tax Expense

13,340

6,873

37,669

23,289

Income Tax Expense

5,483

3,081

15,813

9,473

Net Income

7,857

3,792

21,856

13,816

Less: Net income attributable to noncontrolling interests

Net Income Attributable to Chevron Corporation

$ 7,829

$ 3,768

$ 21,772

$ 13,729

Per Share of Common Stock:

Net Income Attributable to Chevron Corporation

— Basic

$ 3.94

$ 1.89

$ 10.93

$ 6.88

— Diluted

$ 3.92

$ 1.87

$ 10.86

$ 6.84

Dividends

$ 0.78

$ 0.72

$ 2.28

$ 2.12

Weighted Average Number of Shares Outstanding (000s)

— Basic

1,984,643

1,997,721

1,991,091

1,996,376

— Diluted

1,998,673

2,006,785

2,005,381

2,005,677

* Includes excise, value-added and similar taxes:

$ 1,974

$ 2,182

$ 6,372

$ 6,455

See accompanying notes to consolidated financial statements.

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended September 30								Nine Months Ended September 30
	2011				2010				2011				2010
	(Millions of dollars)
Net Income		$	7,857			$	3,792			$	21,856			$	13,816

Currency translation adjustment			(58	)			46				(7	)			33
Unrealized holding gain (loss) on securities:
Net gain (loss) arising during period			1				3				(10	)			(1	)
Derivatives:
Net derivatives (loss) gain on hedge transactions			(4	)			43				(4	)			67
Reclassification to net income of net realized (gain) loss			(2	)			4				(5	)			7
Income taxes on derivatives transactions			2				(16	)			3				(26	)

Total			(4	)			31				(6	)			48
Defined benefit plans:
Actuarial loss:
Amortization to net income of net actuarial loss			169				165				555				497
Actuarial gain arising during period			16				—				71				—
Prior service cost:
Amortization to net income of net prior service credits			(17	)			(15	)			(9	)			(45	)
Defined benefit plans sponsored by equity affiliates			9				8				31				22
Income taxes on defined benefit plans			(65	)			(52	)			(225	)			(173	)

Total			112				106				423				301

Other Comprehensive Gain, Net of Tax			51				186				400				381

Comprehensive Income			7,908				3,978				22,256				14,197
Comprehensive income attributable to noncontrolling interests			(28	)			(24	)			(84	)			(87	)

Comprehensive Income Attributable to Chevron Corporation		$	7,880			$	3,954			$	22,172			$	14,110

See accompanying notes to consolidated financial statements.

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)


	At September 30 2011				At December 31 2010
	(Millions of dollars, except per-share amounts)
ASSETS
Cash and cash equivalents		$	14,229			$	14,060
Time deposits			5,858				2,855
Marketable securities			248				155
Accounts and notes receivable, net			20,878				20,759
Inventories:
Crude oil and petroleum products			3,961				3,589
Chemicals			508				395
Materials, supplies and other			1,603				1,509

Total inventories			6,072				5,493
Prepaid expenses and other current assets			5,740				5,519

Total Current Assets			53,025				48,841
Long-term receivables, net			2,125				2,077
Investments and advances			22,410				21,520
Properties, plant and equipment, at cost			226,536				207,367
Less: Accumulated depreciation, depletion and amortization			108,159				102,863

Properties, plant and equipment, net			118,377				104,504
Deferred charges and other assets			3,026				3,210
Goodwill			4,654				4,617
Assets held for sale			482				—

Total Assets		$	204,099			$	184,769

LIABILITIES AND EQUITY
Short-term debt		$	245			$	187
Accounts payable			20,746				19,259
Accrued liabilities			5,366				5,324
Federal and other taxes on income			4,864				2,776
Other taxes payable			1,117				1,466

Total Current Liabilities			32,338				29,012
Long-term debt			9,384				11,003
Capital lease obligations			114				286
Deferred credits and other noncurrent obligations			18,823				19,264
Noncurrent deferred income taxes			16,126				12,697
Reserves for employee benefit plans			5,638				6,696

Total Liabilities			82,423				78,958

Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued)			—				—
Common stock (authorized 6,000,000,000 shares, $.75 par value, 2,442,676,580 shares issued at September 30, 2011, and December 31, 2010)			1,832				1,832
Capital in excess of par value			15,110				14,796
Retained earnings			136,873				119,641
Accumulated other comprehensive loss			(4,066	)			(4,466	)
Deferred compensation and benefit plan trust			(299	)			(311	)
Treasury stock, at cost (451,192,192 and 435,195,799 shares at September 30, 2011, and December 31, 2010, respectively)			(28,559	)			(26,411	)

Total Chevron Corporation Stockholders’ Equity			120,891				105,081
Noncontrolling interests			785				730

Total Equity			121,676				105,811

Total Liabilities and Equity		$	204,099			$	184,769

See accompanying notes to consolidated financial statements.

CHEVRON CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30
	2011				2010
	(Millions of dollars)
Operating Activities
Net Income		$	21,856			$	13,816
Adjustments
Depreciation, depletion and amortization			9,598				9,624
Dry hole expense			261				381
Distributions less than income from equity affiliates			(114	)			(153	)
Net before-tax gains on asset retirements and sales			(1,064	)			(359	)
Net foreign currency effects			(160	)			203
Deferred income tax provision			1,210				(60	)
Net decrease (increase) in operating working capital			1,504				(132	)
Increase in long-term receivables			(43	)			(47	)
Decrease in other deferred charges			95				48
Cash contributions to employee pension plans			(1,359	)			(895	)
Other			242				676

Net Cash Provided by Operating Activities			32,026				23,102

Investing Activities
Acquisition of Atlas Energy			(3,014	)			—
Advance to Atlas Energy			(403	)			—
Capital expenditures			(19,193	)			(14,108	)
Proceeds and deposits related to asset sales			2,676				543
Net purchases of time deposits			(3,004	)			(3,473	)
Net (purchases) sales of marketable securities			(75	)			41
Repayment of loans by equity affiliates			182				169
Net sales (purchases) of other short-term investments			350				(63	)

Net Cash Used for Investing Activities			(22,481	)			(16,891	)

Financing Activities
Net borrowings (payments) of short-term obligations			5				(169	)
Proceeds from issuance of long-term debt			—				350
Repayments of long-term debt and other financing obligations			(2,755	)			(107	)
Cash dividends – common stock			(4,541	)			(4,233	)
Distributions to noncontrolling interests			(56	)			(56	)
Net (purchases) sales of treasury shares			(2,046	)			245

Net Cash Used for Financing Activities			(9,393	)			(3,970	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents			17				38

Net Change in Cash and Cash Equivalents			169				2,279
Cash and Cash Equivalents at January 1			14,060				8,716

Cash and Cash Equivalents at September 30		$	14,229			$	10,995

See accompanying notes to consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Interim Financial Statements

The accompanying consolidated financial statements of Chevron Corporation and its subsidiaries (the company) have not been audited by an independent registered public accounting firm. In the opinion of the company’s management, the interim data include all adjustments necessary for a fair statement of the results for the interim periods. These adjustments were of a normal recurring nature. The results for the three- and nine-month periods ended September 30, 2011, are not necessarily indicative of future financial results. The term “earnings” is defined as net income attributable to Chevron Corporation.

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 2010 Annual Report on Form 10-K.

Note 2. Noncontrolling Interests

Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income.

Activity for the equity attributable to noncontrolling interests for the first nine months of 2011 and 2010 is as follows:


	2011												2010
	Chevron Corporation Stockholders’ Equity				Noncontrolling Interest				Total Equity				Chevron Corporation Stockholders’ Equity				Noncontrolling Interest				Total Equity
	(Millions of dollars)
Balance at January 1		$	105,081			$	730			$	105,811			$	91,914			$	647			$	92,561
Net income			21,772				84				21,856				13,729				87				13,816
Dividends			(4,541	)			—				(4,541	)			(4,233	)			—				(4,233	)
Distributions to noncontrolling interests			—				(56	)			(56	)			—				(56	)			(56	)
Treasury shares, net			(2,148	)			—				(2,148	)			280				—				280
Other changes, net*			727				27				754				553				44				597

Balance at September 30		$	120,891			$	785			$	121,676			$	102,243			$	722			$	102,965

*	Includes components of comprehensive income, which are disclosed separately in the Consolidated Statement of Comprehensive Income.

Note 3. Information Relating to the Consolidated Statement of Cash Flows

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


	Nine Months Ended September 30
	2011				2010
	(Millions of dollars)
Increase in accounts and notes receivable		$	(1,215	)		$	(13	)
Increase in inventories			(919	)			(608	)
Increase in prepaid expenses and other current assets			(904	)			(646	)
Increase in accounts payable and accrued liabilities			2,493				718
Increase in income and other taxes payable			2,049				417

Net decrease (increase) in operating working capital		$	1,504			$	(132	)

The “Net decrease (increase) in operating working capital” includes reductions of $132 million and $37 million for excess income tax benefits associated with stock options exercised during the nine months ended September 30, 2011, and 2010, respectively. These amounts are offset by an equal amount in “Net (purchases) sales of treasury shares.”

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	Nine Months Ended September 30
	2011			2010
	(Millions of dollars)
Interest on debt (net of capitalized interest)		$	46		$	92
Income taxes			12,982			9,014

The “Acquisition of Atlas Energy” reflects the $3.0 billion of cash paid for all the common shares of Atlas. An “Advance to Atlas Energy” of $403 million was made to facilitate the purchase of a 49 percent interest in Laurel Mountain Midstream LLC on the day of closing. The “Net increase in operating working capital” includes $184 million for payments made in connection with Atlas equity awards subsequent to the acquisition. Refer to Note 16, beginning on page 22 for additional discussion of the Atlas acquisition.

The “Net purchases of time deposits” consisted of the following gross amounts:


	Nine Months Ended September 30
	2011				2010
	(Millions of dollars)
Time deposits purchased		$	(6,439	)		$	(4,868	)
Time deposits matured			3,435				1,395

Net purchases of time deposits		$	(3,004	)		$	(3,473	)

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


	Nine Months Ended September 30
	2011				2010
	(Millions of dollars)
Marketable securities purchased		$	(113	)		$	—
Marketable securities sold			38				41

Net (purchases) sales of marketable securities		$	(75	)		$	41

The “Repayments of long-term debt and other financing obligations” includes $761 million for repayment of Atlas debt and $271 million for payoff of the Atlas revolving credit facility.

The “Net (purchases) sales of treasury shares” represents the cost of common shares acquired less the cost of shares issued for share-based compensation plans. Purchases totaled $3.01 billion and $13.5 million in the first nine months of 2011 and 2010, respectively. During the first nine months of 2011, the company purchased 30.0 million common shares for $3.0 billion under its ongoing share repurchase program. No purchases were made under the company’s share repurchase program in the 2010 period.

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, are as follows:


	Nine Months Ended September 30
	2011				2010
	(Millions of dollars)
Additions to properties, plant and equipment		$	18,458			$	13,242
Additions to investments			639				617
Current year dry hole expenditures			217				348
Payments for other liabilities and assets, net			(121	)			(99	)

Capital expenditures			19,193				14,108
Expensed exploration expenditures			569				431
Assets acquired through capital lease obligations			5				56

Capital and exploratory expenditures, excluding equity affiliates			19,767				14,595
Company’s share of expenditures by equity affiliates			1,035				942

Capital and exploratory expenditures, including equity affiliates		$	20,802			$	15,537

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. The investments are grouped into two business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating segments” as defined in accounting standards for segment reporting (ASC 280). Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; and a gas-to-liquids project. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil and refined products; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant additives. All Other activities of the company include mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, energy services, and alternative fuels and technology companies.

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 ASC 280). The CODM is the company’s Executive Committee (EXCOM), a committee of senior officers that includes the Chief Executive Officer, and EXCOM reports to the Board of Directors of Chevron Corporation.

The operating segments represent components of the company, as described in accounting standards for segment reporting (ASC 280), 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 assesses their performance; and (c) for which discrete financial information is available.

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All Other.” Earnings by major operating area for the three- and nine-month periods ended September 30, 2011, and 2010, are presented in the following table:


	Three Months Ended September 30								Nine Months Ended September 30
Segment Earnings	2011				2010				2011				2010
	(Millions of dollars)
Upstream
United States		$	1,508			$	946			$	4,907			$	3,192
International			4,693				2,618				14,142				9,638

Total Upstream			6,201				3,564				19,049				12,830

Downstream
United States			704				349				1,710				864
International			1,282				216				1,942				872

Total Downstream			1,986				565				3,652				1,736

Total Segment Earnings			8,187				4,129				22,701				14,566

All Other
Interest Expense			—				(7	)			—				(37	)
Interest Income			19				16				56				49
Other			(377	)			(370	)			(985	)			(849	)

Net Income Attributable to Chevron Corporation		$	7,829			$	3,768			$	21,772			$	13,729

Segment Assets Segment assets do not include intercompany investments or intercompany receivables. “All Other” assets consist primarily of worldwide cash, cash equivalents, time deposits and marketable securities; real estate; information systems; mining operations; power generation businesses; energy services; alternative fuels; technology companies; and assets of the corporate administrative functions. Segment assets at September 30, 2011, and December 31, 2010, are as follows:


	At September 30 2011			At December 31 2010
Segment Assets	At September 30 2011			At December 31 2010
	(Millions of dollars)
Upstream
United States		$	36,486		$	26,319
International			95,603			89,306
Goodwill			4,654			4,617

Total Upstream			136,743			120,242

Downstream
United States			21,005			21,406
International			20,476			20,559

Total Downstream			41,481			41,965

Total Segment Assets			178,224			162,207

All Other
United States			9,364			11,125
International			16,511			11,437

Total All Other			25,875			22,562

Total Assets — United States			66,855			58,850
Total Assets — International			132,590			121,302
Goodwill			4,654			4,617

Total Assets		$	204,099		$	184,769

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Segment Sales and Other Operating Revenues Segment sales and other operating revenues, including internal transfers, for the three- and nine-month periods ended September 30, 2011, and 2010, are presented in the following table. Products are transferred between operating segments at internal product values that approximate market prices. Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of fuel and lubricant additives and the transportation and trading of refined products and crude oil. “All Other” activities include revenues from mining operations, power generation businesses, insurance operations, real estate activities, energy services and technology companies.

Sales and Other Operating Revenues


	Three Months Ended September 30								Nine Months Ended September 30
	2011				2010				2011				2010
	(Millions of dollars)
Upstream
United States		$	6,891			$	5,892			$	20,914			$	18,207
International			13,758				9,984				41,165				29,642

Subtotal			20,649				15,876				62,079				47,849
Intersegment Elimination — United States			(4,397	)			(3,299	)			(13,559	)			(10,142	)
Intersegment Elimination — International			(8,608	)			(5,623	)			(26,258	)			(17,141	)

Total Upstream			7,644				6,954				22,262				20,566

Downstream
United States			23,128				18,438				69,174				55,378
International			30,407				23,042				94,644				70,102

Subtotal			53,535				41,480				163,818				125,480
Intersegment Elimination — United States			(20	)			(31	)			(63	)			(80	)
Intersegment Elimination — International			(22	)			(27	)			(73	)			(75	)

Total Downstream			53,493				41,422				163,682				125,325

All Other
United States			401				413				1,163				1,088
International			12				13				34				46

Subtotal			413				426				1,197				1,134
Intersegment Elimination — United States			(278	)			(239	)			(766	)			(652	)
Intersegment Elimination — International			(11	)			(9	)			(31	)			(27	)

Total All Other			124				178				400				455

Sales and Other Operating Revenues
United States			30,420				24,743				91,251				74,673
International			44,177				33,039				135,843				99,790

Subtotal			74,597				57,782				227,094				174,463
Intersegment Elimination — United States			(4,695	)			(3,569	)			(14,388	)			(10,874	)
Intersegment Elimination — International			(8,641	)			(5,659	)			(26,362	)			(17,243	)

Total Sales and Other Operating Revenues		$	61,261			$	48,554			$	186,344			$	146,346

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5. 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, and supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method. The summarized financial information for CUSA and its consolidated subsidiaries is as follows:

		000,000		000,000
	Nine Months Ended September 30
	2011		2010
	(Millions of dollars)
Sales and other operating revenues	$	143,005	$	107,595
Costs and other deductions		135,240		103,433
Net income attributable to CUSA		5,734		3,130

		000,000		000,000
	At September 30		At December 31
	2011		2010
	(Millions of dollars)
Current assets	$	34,995	$	29,211
Other assets		45,290		35,294
Current liabilities		20,084		18,098
Other liabilities		24,587		16,785

Total CUSA net equity	$	35,614	$	29,622

Memo: Total debt	$	14,382	$	8,284

Note 6. Summarized Financial Data — Chevron Transport Corporation

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


	Three Months Ended September 30								Nine Months Ended September 30
	2011				2010				2011				2010
	(Millions of dollars)
Sales and other operating revenues		$	182			$	200			$	604			$	694
Costs and other deductions			232				228				721				755
Net loss attributable to CTC			(47	)			(28	)			(114	)			(54	)


	At September 30 2011			At December 31 2010
	(Millions of dollars)
Current assets		$	15		$	209
Other assets			248			201
Current liabilities			77			101
Other liabilities			65			75

Total CTC net equity		$	121		$	234

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at September 30, 2011.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 7. Income Taxes

Taxes on income for the third quarter and first nine months of 2011 were $5.5 billion and $15.8 billion, respectively, compared with $3.1 billion and $9.5 billion for the corresponding periods in 2010. The associated effective tax rates (calculated as the amount of Income Tax Expense divided by Income Before Income Tax Expense) for the third quarters of 2011 and 2010 were 41 percent and 45 percent, respectively. For the comparative nine-month periods, the effective tax rates were 42 percent and 41 percent, respectively.

The decrease in the effective tax rate between quarterly periods was primarily due to foreign currency remeasurement impacts. An impact from lower utilization of non-U.S. tax credits and the enactment of higher tax rates in the United Kingdom was essentially offset by the effect of non-recurring items, including the sale of non-U.S. assets. For the nine-month comparison, the increase in the effective tax rate was mainly due to lower utilization of non-U.S. tax credits and higher United Kingdom tax rates, which were partially offset by the effects of non-U.S. asset sales and foreign currency remeasurement impacts between periods.

Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions, examinations of tax returns for certain prior tax years had not been completed as of September 30, 2011. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States — 2007, Nigeria — 2000, Angola — 2001 and Saudi Arabia — 2003.

The company engages in ongoing discussions with tax authorities regarding the resolution of tax matters in the various jurisdictions. Both the outcome of these tax matters and the timing of resolution and/or closure of the tax audits are highly uncertain. However, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in significant increases or decreases in the company’s total unrecognized tax benefits within the next 12 months. Given the number of years that still remain subject to examination and the number of matters being examined in the various tax jurisdictions, the company is unable to estimate the range of possible adjustments to the balance of unrecognized tax benefits.

Note 8. Employee Benefits

Chevron has defined benefit pension plans for many employees. The company typically prefunds defined benefit plans as required by local regulations or in certain situations where prefunding provides economic advantages. In the United States, all qualified plans are subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not typically fund U.S. nonqualified 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 (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and the retirees share the costs. Medical coverage for Medicare-eligible retirees in the company’s main U.S. medical plan is secondary to Medicare (including Part D) and the increase to the company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The components of net periodic benefit costs for 2011 and 2010 are as follows:


	Three Months Ended September 30								Nine Months Ended September 30
	2011				2010				2011				2010
Pension Benefits	(Millions of dollars)
United States
Service cost		$	94			$	85			$	281			$	253
Interest cost			116				121				347				364
Expected return on plan assets			(154	)			(135	)			(460	)			(404	)
Amortization of prior service credits			(2	)			(1	)			(6	)			(5	)
Amortization of actuarial losses			77				79				232				238
Settlement losses			52				55				196				165

Total United States			183				204				590				611

International
Service cost			44				38				132				114
Interest cost			81				78				243				230
Expected return on plan assets			(71	)			(60	)			(208	)			(180	)
Amortization of prior service costs			3				5				15				16
Amortization of actuarial losses			23				24				79				74
Curtailment losses			—				—				36				—

Total International			80				85				297				254

Net Periodic Pension Benefit Costs		$	263			$	289			$	887			$	865

Other Benefits*
Service cost		$	14			$	10			$	44			$	29
Interest cost			46				45				136				131
Amortization of prior service credits			(18	)			(19	)			(54	)			(56	)
Amortization of actuarial losses			17				7				48				20

Net Periodic Other Benefit Costs		$	59			$	43			$	174			$	124

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

At the end of 2010, the company estimated it would contribute $950 million to employee pension plans during 2011 (composed of $650 million for the U.S. plans and $300 million for the international plans). Through September 30, 2011, a total of $1.36 billion was contributed (including $1.14 billion to the U.S. plans). Total contributions for the full year are currently estimated to be $1.45 billion ($1.15 billion for the U.S. plans and $300 million for the international plans). Actual contribution amounts are dependent upon plan investment returns, changes in pension obligations, regulatory requirements 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 2011, the company contributed $150 million to its OPEB plans. The company anticipates contributing about $75 million during the remainder of 2011.

Note 9. Litigation

MTBE 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 18 pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to pending lawsuits and claims is not determinable, but could be material to net income in any one period. The company no longer uses MTBE in the manufacture of gasoline in the United States.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

In 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $18.9 billion, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, health care systems and additional infrastructure for Petroecuador. The engineer’s report also asserted that an additional $8.4 billion could be assessed against Chevron for unjust enrichment. In 2009, following the disclosure by Chevron of evidence that the judge participated in meetings in which businesspeople and individuals holding themselves out as government officials discussed the case and its likely outcome, the judge presiding over the case was recused. In 2010, Chevron moved to strike the mining engineer’s report and to dismiss the case based on evidence obtained through discovery in the United States indicating that the report was prepared by consultants for the plaintiffs before being presented as the mining engineer’s independent and impartial work and showing further evidence of misconduct. In August 2010, the judge issued an order stating that he was not bound by the mining engineer’s report and requiring the parties to provide their positions on damages within 45 days. Chevron subsequently petitioned for recusal of the judge, claiming that he had disregarded evidence of fraud and misconduct and that he had failed to rule on a number of motions within the statutory time requirement.

In September 2010, Chevron submitted its position on damages, asserting that no amount should be assessed against it. The plaintiffs’ submission, which relied in part on the mining engineer’s report, took the position that damages are between approximately $16 billion and $76 billion and that unjust enrichment should be assessed in an amount between approximately $5 billion and $38 billion. The next day, the judge issued an order closing the evidentiary phase of the case and notifying the parties that he had requested the case file so that he could prepare a judgment. Chevron petitioned to have that order declared a nullity in light of Chevron’s prior recusal petition, and because procedural and evidentiary matters remained unresolved. In October 2010, Chevron’s motion to recuse the judge was granted. A new judge took charge of the case and revoked the prior judge’s order closing the evidentiary phase of the case. On December 17, 2010, the judge issued an order closing the evidentiary phase of the case and notifying the parties that he had requested the case file so that he could prepare a judgment.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

assessed approximately $8.6 billion in damages and approximately $0.9 billion as an award for the plaintiffs’ representatives. It also assessed an additional amount of approximately $8.6 billion in punitive damages unless the company issued a public apology within fifteen days of the judgment, which Chevron did not do. On February 17, 2011, the plaintiffs appealed the judgment, seeking increased damages, and on March 11, 2011, Chevron appealed the judgment seeking to have the judgment nullified. Chevron continues to believe the Court’s judgment is illegitimate and unenforceable in Ecuador, the United States and other countries. The company also believes the judgment is the product of fraud, and contrary to the legitimate scientific evidence. Chevron cannot predict the timing or ultimate outcome of the appeals process in Ecuador. Chevron will continue a vigorous defense of any imposition of liability. Because Chevron has no substantial assets in Ecuador, Chevron would expect enforcement actions as a result of this judgment to be brought in other jurisdictions. Chevron expects to contest any such actions.

Chevron and Texpet filed an arbitration claim in September 2009 against the Republic of Ecuador before the Permanent Court of Arbitration in The Hague under the Rules of the United Nations Commission on International Trade Law. The claim alleges violations of the Republic of Ecuador’s obligations under the United States-Ecuador Bilateral Investment Treaty (BIT) and breaches of the settlement and release agreements between the Republic of Ecuador and Texpet (described above), which are investment agreements protected by the BIT. Through the arbitration, Chevron and Texpet are seeking relief against the Republic of Ecuador, including a declaration that any judgment against Chevron in the Lago Agrio litigation constitutes a violation of Ecuador’s obligations under the BIT. On February 9, 2011, the Permanent Court of Arbitration issued an Order for Interim Measures requiring the Republic of Ecuador to take all measures at its disposal to suspend or cause to be suspended the enforcement or recognition within and without Ecuador of any judgment against Chevron in the Lago Agrio case pending further order of the Tribunal. Chevron expects to continue seeking permanent injunctive relief and monetary relief before the Tribunal.

Through a series of recent U.S. court proceedings initiated by Chevron to obtain discovery relating to the Lago Agrio litigation and the BIT arbitration, Chevron has obtained evidence that it believes shows a pattern of fraud, collusion, corruption, and other misconduct on the part of several lawyers, consultants and others acting for the Lago Agrio plaintiffs. In February 2011, Chevron filed a civil lawsuit in the Federal District Court for the Southern District of New York against the Lago Agrio plaintiffs and several of their lawyers, consultants and supporters, alleging violations of the Racketeer Influenced and Corrupt Organizations Act and other state laws. Through the civil lawsuit, Chevron is seeking relief that includes an award of damages and a declaration that any judgment against Chevron in the Lago Agrio litigation is the result of fraud and other unlawful conduct and is therefore unenforceable. On March 7, 2011, the Federal District Court issued a preliminary injunction prohibiting the Lago Agrio plaintiffs and persons acting in concert with them from taking any action in furtherance of recognition or enforcement of any judgment against Chevron in the Lago Agrio case pending resolution of Chevron’s civil lawsuit by the Federal District Court. On September 19, 2011, the U.S. Court of Appeals for the Second Circuit vacated the preliminary injunction, stayed the trial on Chevron’s claim for declaratory relief that had been set for November 14, 2011, and denied the defendants’ mandamus petition to recuse the judge hearing the lawsuit. The Second Circuit’s opinion will be forthcoming.

The ultimate outcome of the foregoing matters, including any financial effect on Chevron, remains uncertain. Management does not believe an estimate of a reasonably possible loss (or a range of loss) can be made in this case. Due to the defects associated with the judgment, the 2008 engineer’s report and the September 2010 plaintiffs’ submission, management does not believe these documents have any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to estimate a reasonably possible loss (or a range of loss).

Note 10. Other Contingencies and Commitments

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. Through the end of September 2011, the company had paid $48 million under these indemnities and continues to be obligated up to $250 million for possible additional indemnification payments in the future.

The company has also provided indemnities relating to contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the period of Texaco’s ownership interest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims had to be asserted by February 2009 for Equilon indemnities and must be asserted no later than February 2012 for Motiva indemnities. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments. The company posts no assets as collateral and has made no payments under the indemnities.

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

In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. The acquirer of those assets shared in certain environmental remediation costs up to a maximum obligation of $200 million, which had been reached at December 31, 2009. Under the indemnification agreement, after reaching the $200 million obligation, Chevron is solely responsible until April 2022, when the indemnification expires. The environmental conditions or events that are subject to these indemnities must have arisen prior to the sale of the assets in 1997.

Although the company has provided for known obligations under this indemnity 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.

Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

Other Contingencies On April 26, 2010, a California appeals court issued a ruling related to the adequacy of an Environmental Impact Report (EIR) supporting the issuance of certain permits by the city of Richmond, California, to replace and upgrade certain facilities at Chevron’s refinery in Richmond. Settlement discussions with plaintiffs in the case ended late fourth quarter 2010, and on March 3, 2011, the trial court entered a final judgment and peremptory writ ordering the City to set aside the project EIR and conditional use permits and enjoining Chevron from any further work. On May 23, 2011, the company filed an application with the City Planning Department for a conditional use permit for a revised project to complete construction of the hydrogen plant, certain sulfur removal facilities and related infrastructure. On June 10, 2011, the City published its Notice of Preparation of the revised EIR for the project. The revised and recirculated EIR is intended to comply with the appeals court decision. Management believes the outcomes associated with the project are uncertain. Due to the uncertainty of the company’s future course of action, or potential outcomes of any action or combination of actions, management does not believe an estimate of the financial effects, if any, can be made at this time. However, the company’s ultimate exposure may be significant to net income in any one future period.

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

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

Note 11. Fair Value Measurements

Accounting standards for fair value measurement (ASC 820) establish a framework for measuring fair value and stipulate disclosures about fair value measurements. The standards apply to recurring and nonrecurring fair value measurements of financial and nonfinancial assets and liabilities. Among the required disclosures is the fair value hierarchy of inputs the company uses to value an asset or a liability. The three levels of the fair value hierarchy are described as follows:

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

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The fair value hierarchy for recurring assets and liabilities measured at fair value at September 30, 2011 and December 31, 2010, is as follows:

Assets and Liabilities Measured at Fair Value on a Recurring Basis

(Millions of dollars)


	At September 30, 2011												At December 31, 2010
	Total			Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3
Marketable Securities		$	248		$	248		$	—		$	—		$	155		$	155		$	—		$	—
Derivatives			165			55			110			—			122			11			111			—

Total Assets at Fair Value		$	413		$	303		$	110		$	—		$	277		$	166		$	111		$	—

Derivatives		$	71		$	64		$	7		$	—		$	171		$	75		$	96		$	—

Total Liabilities at Fair Value		$	71		$	64		$	7		$	—		$	171		$	75		$	96		$	—

Marketable Securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets and liabilities. The fair values reflect the cash that would have been received if the instruments were sold at September 30, 2011.

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

The company’s derivative instruments principally include futures, swaps, options and forward contracts for crude oil, natural gas and refined products. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange.

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

The fair value hierarchy for nonrecurring assets and liabilities measured at fair value at September 30, 2011, is as follows:

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

(Millions of dollars)


	At September 30, 2011
													Before-Tax Loss
	Total			Level 1			Level 2			Level 3			Three Months Ended			Nine Months Ended
Properties, plant and equipment, net (held and used)		$	22		$	—		$	—		$	22		$	36		$	86
Properties, plant and equipment, net (held for sale)			—			—			—			—			39			49
Investments and advances			—			—			—			—			11			14

Total Assets at Fair Value		$	22		$	—		$	—		$	22		$	86		$	149

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Impairments of “Properties, plant and equipment” The company did not have any material long-lived assets measured at fair value on a nonrecurring basis to report in 2011. The fair values were determined from internal cash flow models, using discount rates consistent with those used by the company to evaluate cash flows of other assets of a similar nature. The losses on assets held for sale during third quarter 2011 were the result of an offer tendered to a prospective buyer.

Impairments of “Investments and advances” The company did not have any material investments and advances measured at fair value on a nonrecurring basis to report in the third quarters 2011 and 2010. The fair values were determined from internal cash flow models, using discount rates consistent with those used by the company to evaluate cash flows of other investments of a similar nature.

Assets and Liabilities not Required to be Measured at Fair Value The company holds cash equivalents and bank time deposits in U.S. and non-U.S. portfolios. The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less and money market funds. “Cash and cash equivalents” had carrying/fair values of $14.2 billion and $14.1 billion at September 30, 2011, and December 31, 2010, respectively. The instruments held in “Time deposits” are bank time deposits with maturities greater than 90 days, and had carrying/fair values of $5.9 billion and $2.9 billion at September 30, 2011, and December 31, 2010, respectively. The fair values of cash, cash equivalents and bank time deposits reflect the cash that would have been received if the instruments were settled at September 30, 2011.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $505 million and $855 million at September 30, 2011, and December 31, 2010, respectively. At September 30, 2011, these investments include restricted funds related to various U.S. refinery projects, which are reported in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt of $4.1 billion and $5.6 billion at September 30, 2011, and December 31, 2010 had estimated fair values of $4.9 billion and $6.3 billion, respectively.

The carrying values of short-term financial assets and liabilities on the consolidated balance sheet approximate their fair values. Fair value remeasurements of other financial instruments at September 30, 2011 and 2010 were not material.

Note 12. Derivative Instruments and Hedging Activities

The company’s derivative instruments principally include crude oil, natural gas and refined product futures, swaps, options, and forward contracts. None of the company’s derivative instruments is designated as a hedging instrument, although certain of the company’s affiliates make such designation. The company’s derivatives are not material to the company’s financial position, results of operations or liquidity. The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodities and other derivatives activities.

Derivative instruments measured at fair value at September 30, 2011, and December 31, 2010, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are as follows:

Consolidated Balance Sheet: Fair Value of Derivatives Not Designated as Hedging Instruments

(Millions of Dollars)


Type of Contract	Balance Sheet Classification	At September 30 2011			At December 31 2010
Commodity	Accounts and notes receivable, net		$	101		$	58
Commodity	Long-term receivables, net			64			64

Total Assets at Fair Value			$	165		$	122

Commodity	Accounts payable		$	42		$	131
Commodity	Deferred credits and other noncurrent obligations			29			40

Total Liabilities at Fair Value			$	71		$	171

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Consolidated Statement of Income: The Effect of Derivatives Not Designated as Hedging Instruments

(Millions of dollars)


		Gain / (Loss) Three Months Ended September 30								Gain / (Loss) Nine Months Ended September 30
Type of Contract	Statement of Income Classification	2011				2010				2011				2010
Commodity	Sales and other operating revenues		$	130			$	(58	)		$	(194	)		$	94
Commodity	Purchased crude oil and products			(11	)			(12	)			20				(38	)
Commodity	Other income			3				7				1				(2	)

			$	122			$	(63	)		$	(173	)		$	54

Note 13. New Accounting Standards

Fair Value Measurement (Topic 820), Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (ASU 2011-04) In May 2011, the FASB issued ASU 2011-04, which becomes effective for the company on January 1, 2012. The amendments in ASU 2011-04 result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRS. As a result of these amendments, the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements were changed. The company does not anticipate changes to its existing classification and measurement of fair value when the amended standard becomes effective. However, the company’s disclosures on certain items not required to be measured at fair value will be expanded when the amended standard becomes effective.

Comprehensive Income (Topic 220), Presentation of Comprehensive Income (ASU 2011-05) The FASB issued ASU 2011-05 in June 2011. This standard becomes effective for the company on January 1, 2012. ASU 2011-05 changes the presentation requirements for comprehensive income. Adoption of the standard is not expected to have a significant impact on the company’s current financial statement presentation.

Intangibles — Goodwill and Other (Topic 350), Testing Goodwill for Impairment (ASU 2011-08) In September 2011, the FASB issued ASU 2011-08, which becomes effective for the company on January 1, 2012. The standard simplifies how companies test goodwill for impairment. The company does not anticipate any impact to its results of operations, financial position or liquidity when the guidance becomes effective.

Note 14. Restructuring and Reorganization Costs

In the first quarter 2010, the company announced employee reduction programs related to the restructuring and reorganization of its downstream businesses and corporate staffs. Total employee terminations under the programs are currently expected to be approximately 2,900 employees. About 1,300 of the affected employees are located in the United States. About 2,300 employees have been terminated through September 30, 2011, and the programs are expected to be substantially completed by the end of 2011.

A before-tax charge of $244 million was recorded in first quarter 2010 associated with these programs, of which $138 million remained outstanding at December 31, 2010. During the first nine months of 2011, the company made payments of $62 million associated with these liabilities. The majority of the payments were in Downstream. The balance at September 30, 2011, was classified as a current liability on the Consolidated Balance Sheet.


	Amounts Before Tax
	(Millions of dollars)
Balance at December 31, 2010		$	138
Adjustment			(21	)
Payments			(62	)

Balance at September 30, 2011		$	55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 15. Assets Held For Sale

At September 30, 2011, the company classified $0.5 billion of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets are associated with upstream and midstream assets that are anticipated to be sold in 2011. The company’s Pembroke Refinery and other downstream assets in the United Kingdom and Ireland, previously classified as “held for sale”, were divested on August 1, 2011. The revenues and earnings contributions of these assets in the first nine months of 2011 were not material.

Note 16. Acquisition of Atlas Energy, Inc.

On February 17, 2011, the company acquired Atlas Energy, Inc. (Atlas), which held one of the premier acreage positions in the Marcellus Shale, concentrated in southwestern Pennsylvania. The aggregate purchase price of Atlas was approximately $4.5 billion, which included approximately $3.0 billion cash for all the common shares of Atlas, a $403 million cash advance to facilitate Atlas’ purchase of a 49 percent interest in Laurel Mountain Midstream LLC and about $1.1 billion of assumed debt. Subsequent to the close of the transaction, the company paid off the assumed debt and made payments of $184 million in connection with Atlas equity awards. As part of the acquisition, Chevron assumed the terms of a carry arrangement whereby Reliance Marcellus, LLC funds 75 percent of Chevron’s drilling costs, up to $1.3 billion.

The acquisition was accounted for as a business combination (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Provisional fair value measurements were made in the first quarter 2011 for acquired assets and assumed liabilities, and adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as information necessary to complete the analysis is obtained. No adjustments to the provisional measurements were made in the third quarter 2011. The company expects the measurement process will be finalized by the end of 2011.

Proforma financial information is not presented as it would not be materially different from the information presented in the Consolidated Statement of Income.

The following table summarizes the provisional measurement of the assets acquired and liabilities assumed:


	At February 17, 2011
	(Millions of dollars)
Current assets		$	150
Investments and long-term receivables			456
Properties			6,051
Goodwill			39
Other assets			5

Total assets acquired			6,701

Current liabilities			(560	)
Long-term debt and capital leases			(761	)
Deferred income taxes			(1,918	)
Other liabilities			(25	)

Total liabilities assumed			(3,264	)

Net assets acquired		$	3,437

Properties were measured primarily using an income approach. The fair values of the acquired oil and gas properties were based on significant inputs not observable in the market, and thus represent Level 3 measurements. Significant inputs included estimated resource volumes, assumed future production profiles, estimated future commodity prices, a discount rate of 8 percent, and assumptions on the timing and amount of future operating and development costs. All the properties are in the United States and are included in the Upstream segment.

The acquisition date fair value of the consideration transferred was $3.4 billion in cash. The $39 million of goodwill was assigned to the Upstream segment and represents the amount of the consideration transferred in excess of the values assigned to the individual assets acquired and liabilities assumed. Goodwill represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. None of the goodwill is deductible for tax purposes. Goodwill recorded in the acquisition is not subject to amortization, but will be tested periodically for impairment as required by the applicable accounting standard (ASC 350).

Item 2.

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

Third Quarter 2011 Compared with Third Quarter 2010

And Nine Months 2011 Compared with Nine Months 2010

Key Financial Results

Earnings by Business Segment


	Three Months Ended September 30								Nine Months Ended September 30
	2011				2010				2011				2010
	(Millions of dollars)
Upstream
United States		$	1,508			$	946			$	4,907			$	3,192
International			4,693				2,618				14,142				9,638

Total Upstream			6,201				3,564				19,049				12,830

Downstream
United States			704				349				1,710				864
International			1,282				216				1,942				872

Total Downstream			1,986				565				3,652				1,736

Total Segment Earnings			8,187				4,129				22,701				14,566
All Other			(358	)			(361	)			(929	)			(837	)

Net Income Attributable to Chevron Corporation(1)(2)		$	7,829			$	3,768			$	21,772			$	13,729


(1) Includes foreign currency effects		$	449			$	(367	)		$	204			$	(324	)
(2) Also referred to as “earnings” in the discussions that follow.

Net income attributable to Chevron Corporation for the third quarter 2011 was $7.8 billion ($3.92 per share — diluted), compared with $3.8 billion ($1.87 per share — diluted) in the corresponding 2010 period. Net income attributable to Chevron Corporation for the first nine months of 2011 was $21.8 billion ($10.86 per share — diluted), versus $13.7 billion ($6.84 per share — diluted) in the first nine months of 2010.

Upstream earnings in the third quarter 2011 were $6.2 billion, compared with $3.6 billion in the 2010 quarter. Earnings for the first nine months of 2011 were $19.0 billion, versus $12.8 billion a year earlier. The increase between the comparative periods was mainly due to higher crude oil realizations.

Downstream earnings were $2.0 billion in the third quarter 2011, compared with $565 million in the year-earlier period. Earnings for the first nine months of 2011 were $3.7 billion, versus $1.7 billion in the corresponding 2010 period. The increase between the comparative periods was primarily associated with gains on asset sales and improved margins on refined products. Higher earnings from chemicals operations — primarily from the 50 percent-owned Chevron Phillips Chemical Company LLC — also contributed to the increase for the nine-month comparative period.

Refer to pages 28 through 30 for additional discussion of results by business segment and “All Other” activities for the third quarter and first nine months of 2011 versus the same periods in 2010.

Business Environment and Outlook

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

Earnings of the company depend mostly on the profitability of its upstream and downstream 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 other activities and investments. Earnings for the company in any period may also be influenced by events or transactions that are infrequent or unusual in nature.

The company’s operations, especially upstream, can also be affected by changing economic, regulatory and political environments in the various countries in which it operates, including the United States. Civil unrest, acts of violence or strained relations between a government and the company or other governments may impact the company’s operations or investments. Those developments have at times significantly affected the company’s operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries.

To sustain its long-term competitive position in the upstream business, the company must develop and replenish an inventory of projects that offer attractive 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. From time to time, certain governments have sought to renegotiate contracts or impose additional costs on the company. Governments may attempt to do so in the future. The company will continue to monitor these developments, take them into account in evaluating future investment opportunities, and otherwise seek to mitigate any risks to the company’s current operations or future prospects.

The company also continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value or to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and growth. Refer to the “Results of Operations” section, beginning on page 28, for discussions of net gains on asset sales during 2011. Asset dispositions and restructurings may also occur in future periods and could result in significant gains or losses.

In recent years, Chevron and the oil and gas industry generally experienced an increase in certain costs that exceeded the general trend of inflation in many areas of the world. This increase in costs affected the company’s operating expenses and capital programs for all business segments, but particularly for Upstream. The company continues to actively manage its schedule of work, contracting, procurement and supply-chain activities to effectively manage costs.

The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity and the implications for the company of movements in prices for crude oil and natural gas. Management takes these developments into account in the conduct of daily operations and for business planning. The company remains confident of its underlying financial strength to address potential challenges presented in the current environment. (Refer also to the “Liquidity and Capital Resources” section beginning on page 34.)

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

Upstream Earnings for the upstream segment are closely aligned with industry price levels for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be

caused by military conflicts, civil unrest or political uncertainty. Moreover, any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments and seeks to manage risks in operating its facilities and businesses. Besides the impact of fluctuations in prices for crude oil and natural gas, the longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts and changes in tax laws and regulations.

Price levels for capital and exploratory costs and operating expenses associated with the production of crude oil and natural gas can also be subject to external factors beyond the company’s control. External factors include not only the general level of inflation, but also commodity prices and prices charged by the industry’s material and service providers, which can be affected by the volatility of the industry’s own supply-and-demand conditions for such materials and services. Capital and exploratory expenditures and operating expenses can also be affected by damage to production facilities caused by severe weather or civil unrest.

The following chart shows the trend in benchmark prices for West Texas Intermediate (WTI) crude oil, Brent crude oil and U.S. Henry Hub natural gas. The WTI price averaged $79 per barrel for the full-year 2010. During the first nine months of 2011, WTI averaged $95 and ended October at $93. The Brent price averaged $80 per barrel for the full-year 2010. During the first nine months of 2011, Brent averaged $112 and ended October at $110. The majority of the company’s equity crude production is priced based on the Brent benchmark. Recently, due to excess supply of WTI, WTI has traded at a discount to Brent.

LOGO

A differential in crude oil prices also exists between high quality (high-gravity, low-sulfur) crudes and those of lower quality (low-gravity, high-sulfur). The amount of the differential in any period is associated with the supply of heavy crude available versus the demand, which is a function of the number of refineries that are able to process this lower quality feedstock into light products (motor gasoline, jet fuel, aviation gasoline and diesel fuel). The differential widened in the first nine months of 2011 primarily due to rising diesel prices and lower availability of light, sweet crude oil due to supply disruptions in Libya. Chevron produces or shares in the production of heavy crude oil in California, Chad, Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom sector of the North Sea. (See page 33 for the company’s average U.S. and international crude oil realizations.)

In contrast to price movements in the global market for crude oil, price changes for natural gas in many regional markets are more closely aligned with supply-and-demand conditions in those markets. In the United States, prices at Henry Hub averaged $4.20 per thousand cubic feet (MCF) in the first nine months of 2011, compared with $4.60 during the first nine months of 2010. At the end of October 2011, the Henry Hub spot price was $3.66 per MCF. Fluctuations in the price for natural gas in the United States are closely associated with customer demand relative to the volumes produced in North America and the level of inventory in underground storage.

Certain international natural gas markets in which the company operates have different supply, demand and regulatory circumstances, which historically have resulted in lower average sales prices for the company’s production of natural gas in these locations. In some of these locations, Chevron is investing in long-term projects to install infrastructure to produce and liquefy natural gas for transport by tanker to other markets where prices are higher. International natural gas realizations averaged $5.30 per MCF during the first nine months of 2011, compared with $4.60 in the same period last year. (See page 33 for the company’s average natural gas realizations for the U.S. and international regions.)

The company’s worldwide net oil-equivalent production in the first nine months of 2011 averaged 2.684 million barrels per day. About one-fifth of the company’s net oil-equivalent production in the first nine months of 2011

occurred in the OPEC-member countries of Angola, Nigeria, Venezuela and the Partitioned Zone between Saudi Arabia and Kuwait. OPEC quotas had no effect on the company’s net crude oil production for the first nine months of 2011 and 2010. At the latest meeting in June 2011, members of OPEC supported maintaining production quotas in effect since December 2008.

Third quarter 2011 oil-equivalent production of 2.599 million barrels per day was negatively impacted by planned turnarounds, as well as unplanned tropical storm related downtime and the effects of damage to a third-party pipeline in Thailand. The company expects oil-equivalent production to increase by 100,000 to 150,000 barrels per day between the third and fourth quarters of 2011, reflecting the completion of repairs and planned turnarounds, as well as new production. This estimate is subject to many factors and uncertainties, including additional quotas that may be imposed by OPEC, price effects on volumes produced under cost-recovery and variable-royalty contract provisions, changes in fiscal terms or restrictions on the scope of company operations, delays in project startups, fluctuations in demand for natural gas in various markets, weather conditions that may shut in production, civil unrest, changing geopolitics, delays in completion of maintenance turnarounds, greater-than-expected declines in production from mature fields, or other disruptions to operations. Beyond 2011, the outlook for future production levels is also 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. Investments in upstream projects generally begin well in advance of the start of the associated crude oil and natural gas production. A significant majority of Chevron’s upstream investment is made outside the United States.

Gulf of Mexico Update The company has three drillships operating in the deepwater Gulf of Mexico and a fourth drillship is expected to begin operating in the fourth quarter 2011. The company has received approval of several exploration plan and drilling permit applications for the Gulf of Mexico in 2011.

Refer to the “Results of Operations” section on pages 28 through 29 for additional discussion of the company’s upstream business.

Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, and petrochemicals. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and petrochemicals and by changes in the price of crude oil, other refinery and petrochemical feedstocks, and natural gas. Industry margins can also be influenced by inventory levels, geopolitical events, cost of materials and services, refinery or chemical plant capacity utilization, maintenance programs and disruptions at refineries or chemical plants resulting from unplanned outages due to severe weather, fires or other operational events.

Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining, marketing and petrochemical assets, the effectiveness of the crude oil and product supply functions and the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refining, marketing and petrochemical assets.

The company’s most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Asia and southern Africa. Chevron operates or has significant ownership interests in refineries in each of these areas. In the first nine months of 2011, the company’s margins improved over 2010, supported by higher global product demand and tighter global refined product supplies.

In first quarter 2010, the company announced that its downstream businesses would be restructured to improve operating efficiency and achieve sustained improvement in financial performance. As part of this restructuring, employee-reduction programs were announced for the United States and international downstream operations. Approximately 2,500 employees in the downstream operations are expected to be terminated under these programs and substantially all will be terminated by the end of 2011. About 900 of the affected employees are located in the United States. Through third quarter 2011, 2,000 employees were terminated worldwide. Refer to Note 14 of the Consolidated Financial Statements, on page 21, for further discussion.

In 2010, the company solicited bids for 13 U.S. terminals and certain operations in Europe (including the company’s Pembroke Refinery), the Caribbean, and select Central America and Africa markets. These sales are

part of the company’s ongoing effort to concentrate downstream resources and capital on strategic, global assets. Through third quarter 2011, the company completed the sale of 12 U.S. terminals, certain marketing businesses in Africa, LPG storage and distribution operations in China, and its fuels marketing and aviation businesses in 15 countries in the Caribbean and Central America regions. In February 2011, the company announced an agreement to sell its fuels, finished lubricants and aviation fuels businesses in Spain. This sale is expected to be completed in the first quarter 2012 pending customary regulatory approvals. On August 1, 2011 the company completed the sale of its 220,000-barrel-per-day Pembroke Refinery and its fuels marketing and aviation assets in the United Kingdom and Ireland.

Refer to the “Results of Operations” section on pages 29 through 30, for additional discussion of the company’s downstream operations.

All Other consists of mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, energy services, and alternative fuels and technology companies. In first quarter 2010, employee-reduction programs were announced for the corporate staffs. Through the third quarter 2011, 300 employees were terminated, and it is expected that approximately 400 employees from the corporate staffs will be terminated under the programs by the end of 2011. Refer to Note 14 of the Consolidated Financial Statements, on page 21, for further discussion.

Operating Developments

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

•

Australia — Reached final investment decision on the Wheatstone liquefied natural gas (LNG) project.

•

Australia — Signed binding Sales and Purchase Agreement with Kyushu Electric for Wheatstone LNG and for Kyushu Electric to acquire an equity share in the field licenses and LNG facilities.

•

Australia — Announced two deepwater natural gas discoveries in the Carnarvon Basin offshore Western Australia, Acme West-1 and Acme West-2 in 67 percent-owned Block WA-205-P. These discoveries are expected to help underpin potential expansion opportunities at the Wheatstone LNG facilities.

•

Thailand — Announced first gas at the Platong Gas II natural gas development in the Gulf of Thailand.

•

United Kingdom — Reached final investment decision for the Clair Ridge project in the North Sea.

•

United States — Announced a new oil discovery at the Moccasin prospect in the deepwater Gulf of Mexico.

•

United States — Reached final investment decision for the Tubular Bells project in the deepwater Gulf of Mexico.

In the downstream business, the company completed the sale of its refining, fuels marketing and aviation assets in the United Kingdom and Ireland on August 1, 2011. The company also completed the sale of certain other fuels marketing and aviation businesses in the Caribbean and South America in the third quarter 2011.

The company purchased $1.25 billion of its common stock in the third quarter 2011 under its share repurchase program.

Results of Operations

Business Segments The following section presents the results of operations for the company’s business segments — Upstream and Downstream — as well as for “All Other.” (Refer to Note 4, beginning on page 9, for a discussion of the company’s “reportable segments,” as defined under the accounting standards for segment reporting.)

Upstream

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars)

U.S. Upstream Earnings

1,508

946

4,907

3,192

U.S. upstream earnings of $1.51 billion in the third quarter of 2011 increased $562 million from the same period last year. The benefit of higher crude oil realizations of $750 million was partly offset by decreased net oil-equivalent production of about $130 million.

Earnings for the first nine months of 2011 were approximately $4.91 billion, up about $1.72 billion from the corresponding period in 2010. The benefit of higher crude oil realizations of $2.2 billion was partly offset by the effect of decreased net oil-equivalent production of about $300 million and higher operating expenses of about $150 million.

The company’s average realization per barrel of crude oil and natural gas liquids in the third quarter of 2011 was $97, up from $69 a year earlier. For the nine-month periods, average realizations were about $97 and $70 for 2011 and 2010, respectively. The average natural gas realization in the third quarter 2011 was $4.14 per thousand cubic feet, compared with $4.06 in the year-ago period. The average nine-month realizations were $4.18 in 2011 and $4.47 in 2010.

Net oil-equivalent production of 662,000 barrels per day in the third quarter 2011 was down 30,000 barrels per day, or about 4 percent, from a year earlier. The decrease in production was associated with normal field declines and tropical storm and maintenance-related downtime. Partially offsetting this decrease was production from the acquisition of Atlas Energy, Inc. in the first quarter 2011 and increases at the Perdido project in the Gulf of Mexico.

Nine months 2011 production was 684,000 barrels per day, down 27,000 from the corresponding 2010 period. The decrease was associated with normal field declines and maintenance-related downtime. Partially offsetting this decrease was production from the acquisition of Atlas Energy, Inc. and increases at the Perdido project in the Gulf of Mexico. The net liquids component of oil-equivalent production was 453,000 barrels per day and 471,000 barrels per day for the third quarter and nine months of 2011, respectively. Those volumes were 6 percent and 4 percent lower than the corresponding 2010 periods. Net natural gas production of 1.26 billion cubic feet per day in the third quarter 2011 remained flat compared with the year-ago period, and decreased 3 percent to 1.28 billion cubic feet per day in the nine-month comparative period.


	Three Months Ended September 30							Nine Months Ended September 30
	2011			2010				2011			2010
	(Millions of dollars)
International Upstream Earnings*		$	4,693		$	2,618			$	14,142		$	9,638


* Includes foreign currency effects		$	304		$	(245	)		$	214		$	(240	)

International upstream earnings of $4.69 billion in the third quarter 2011 increased $2.08 billion from the corresponding period in 2010. The benefit of higher crude oil realizations of about $1.9 billion was partly offset by higher tax charges of about $500 million. Other items of lesser significance were largely offsetting. Foreign currency effects increased earnings by $304 million in the 2011 third quarter, compared with a decrease of $245 million a year earlier.

Earnings for the first nine months of 2011 were $14.14 billion, up $4.50 billion from the same period in 2010. Higher prices for crude oil increased earnings by $5.8 billion. This benefit was partly offset by higher operating expenses, including fuel, of about $800 million, and higher tax items of about $800 million. Foreign currency effects increased earnings by $214 million in the first nine months of 2011, compared with a decrease of $240 million a year earlier.

The average realization per barrel of crude oil and natural gas liquids in the third quarter 2011 and nine-month period were $103 and $102, respectively, compared with about $70 in the corresponding 2010 periods. The average natural gas realization per thousand cubic feet in the 2011 third quarter and nine-month period were $5.50 per thousand cubic feet and $5.33, respectively, compared with $4.73 and $4.58 in the corresponding 2010 periods.

International net oil-equivalent production of 1.94 million barrels per day in the third quarter 2011 decreased 109,000 barrels per day from a year ago. Production increases from project ramp-ups in Canada and Brazil were more than offset by maintenance-related downtime, an approximate 39,000 barrels per day negative effect of higher prices on volumes produced under cost-recovery and variable-royalty contract provisions, and normal field declines. The maintenance-related downtime included the effects of damage to a third-party pipeline in Thailand, since remediated, which resulted in the shut-in of production.

International net oil-equivalent production for the nine-months of 2011 was 2.00 million barrels per day, down 44,000 barrels per day from the 2010 period. Production increases from project ramp-ups in Canada and Brazil were more than offset by an approximate 37,000 barrels per day negative effect of higher prices on volumes produced under cost-recovery and variable-royalty contract provisions, as well as normal field declines and maintenance-related downtime. The maintenance-related downtime included the effects of damage to a third-party pipeline in Thailand, since remediated, which resulted in the shut-in of production.

The net liquids component of oil-equivalent production was 1.35 million barrels per day in the third quarter 2011 and 1.39 million barrels per day in the nine-month period, decreases of 5 and 2 percent for the respective periods. Net natural gas production totaled 3.50 billion cubic feet per day in the third quarter 2011 and 3.66 billion cubic feet per day in the first nine months, a decrease of 7 percent and 2 percent, from the respective 2010 periods.

Downstream

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars)

U.S. Downstream Earnings

704

349

1,710

864

U.S. downstream earned $704 million in the third quarter 2011, compared with earnings of $349 million a year earlier. Earnings mainly benefited from improved margins on refined product sales of $260 million and lower operating expenses of $40 million.

Earnings for the first nine months of 2011 were $1.71 billion, compared with $864 million in the same period of 2010. Earnings benefited by $600 million from improved margins on refined products, $180 million from higher earnings from the 50 percent-owned Chevron Phillips Chemical Company LLC, and $120 million from lower operating expenses.

Refinery crude-input of 897,000 barrels per day in the third quarter 2011 increased 17,000 barrels per day from the year-ago period. Inputs of 883,000 barrels per day for the nine months of 2011 decreased about 1 percent from the corresponding 2010 period.

Refined product sales of 1.25 million barrels per day for the quarterly period and 1.27 million barrels per day for the nine-month period of 2011 both declined 7 percent. The declines were mainly due to lower gas oil, kerosene, and gasoline sales for both periods. Branded gasoline sales of 529,000 and 514,000 barrels per day for the third quarter and nine months in 2011 decreased 8 percent and 12 percent, respectively, due to weaker demand and previously announced exits from selected eastern U.S. retail markets in both comparative periods.


	Three Months Ended September 30							Nine Months Ended September 30
	2011			2010				2011			2010
	(Millions of dollars)
International Downstream Earnings*		$	1,282		$	216			$	1,942		$	872


* Includes foreign currency effects		$	148		$	(118	)		$	16		$	(83	)

International downstream operations earned $1.28 billion in the third quarter 2011, compared with $216 million a year earlier. Earnings benefited from gains on asset sales, including approximately $500 million from the sale of the Pembroke Refinery and related marketing assets in the United Kingdom and Ireland. Also contributing to earnings were improved refined product margins of $100 million in the 2011 third quarter. Foreign currency effects increased earnings by $148 million in the 2011 quarter, compared with a decrease of $118 million a year earlier.

Earnings for the first nine months of 2011 were $1.94 billion, compared with $872 million in the corresponding 2010 period. Gains on asset sales benefited earnings by $720 million. Also contributing to earnings were improved margins of $380 million and the absence of 2010 charges of $110 million related to employee reductions. These benefits were partly offset by unfavorable effects of derivative instruments of about $240 million and higher operating expenses of $200 million. Foreign currency effects increased earnings by $16 million in 2011, compared with a decrease of $83 million a year earlier.

Refinery crude-input of 882,000 barrels per day in the 2011 third quarter decreased 145,000 barrels per day from third quarter 2010. For the nine months of 2011, crude oil inputs were 977,000 barrels per day, down 14,000 barrels per day from the year-ago period. The decrease for both comparative periods was attributable mainly to the sale of the Pembroke Refinery on August 1, 2011.

Total refined product sales of 1.59 million barrels per day for the quarterly period and 1.73 million barrels per day for the nine-month period of 2011 declined 10 percent and 1 percent, respectively. The declines were primarily related to the sale of the company’s refining and marketing assets in the United Kingdom and Ireland. Excluding the impact of 2011 asset sales, sales volumes were essentially flat and up 3 percent, respectively, between the comparative periods.

All Other


	Three Months Ended September 30								Nine Months Ended September 30
	2011				2010				2011				2010
	(Millions of dollars)
Net Charges*		$	(358	)		$	(361	)		$	(929	)		$	(837	)

* Includes foreign currency effects		$	(3	)		$	(4	)		$	(26	)		$	(1	)

All Other consists of mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, energy services, and alternative fuels and technology companies.

Net charges in the third quarter 2011 were $358 million, compared with $361 million in the year-ago period. For the nine months of 2011, net charges were $929 million, compared with $837 million a year earlier. Corporate expenses and net charges for employee compensation and benefits were higher in the 2011 nine-month period.

Consolidated Statement of Income

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

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars)

Sales and other operating revenues

61,261

48,554

186,344

146,346

Sales and other operating revenues for the quarterly and nine-month periods increased $13 billion and $40 billion, respectively, mainly due to higher prices for crude oil, natural gas and refined products.

threem

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars)

Income from equity affiliates

2,227

1,242

5,796

4,127

Income from equity affiliates increased between the quarterly and nine-month periods mainly due to higher upstream-related earnings from Tengizchevroil in Kazakhstan as a result of higher prices for crude oil. Downstream-related earnings were also higher between the comparative periods primarily due to a favorable swing in foreign currency effects at GS Caltex in South Korea and higher earnings from Chevron Phillips Chemical Company LLC, as a result of higher margins on sales of commodity chemicals.

threemo

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars)

Other income

944

(78

)

1,581

428

Other income for the quarterly and nine month periods increased mainly due to higher gains on asset sales and a favorable swing in foreign currency effects.

threemon

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars)

Purchased crude oil and products

37,600

28,610

113,560

86,358

Purchases increased $9 billion and $27 billion in the quarterly and nine-month periods mainly due to higher prices for crude oil and refined products.

$19,116

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars)

Operating, selling, general and administrative expenses

6,493

5,846

19,116

17,204

Operating, selling, general and administrative expenses increased $647 million between quarters and $1.91 billion between the nine-month periods. Higher expenses were primarily related to fuel, and employee compensation and benefits. These accounted for approximately $430 million and $1.7 billion of the increase between the quarterly and nine-month periods, respectively. Increased fuel purchases reflected a new commercial arrangement that replaced a prior product exchange agreement for upstream operations in Indonesia.

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars)

Exploration expenses

240

420

830

812

The decrease in exploration expenses between quarterly periods was primarily due to lower amounts for well write-offs.

thre

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars)

Depreciation, depletion and amortization

3,215

3,401

9,598

9,624

The decrease in the third quarter and nine-month periods mainly reflected lower production levels and lower depreciation rates for certain oil and gas producing fields.

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars)

Taxes other than on income

3,544

4,559

12,948

13,568

Taxes other than on income decreased primarily due to lower import duties in the United Kingdom reflecting the sale of the Pembroke Refinery and other downstream assets, partly offset by higher export duties in the company’s South Africa downstream operations.

mont

Three Months Ended
September 30

Nine Months Ended
September 30

2011

2010

2011

2010

(Millions of dollars)

Income tax expense

5,483

3,081

15,813

9,473

Effective income tax rates for the 2011 and 2010 third quarters were 41 percent and 45 percent, respectively. For the year-to-date periods, the effective tax rates were 42 and 41 percent, respectively. The decrease in the effective tax rate between quarterly periods was primarily due to foreign currency remeasurement impacts. An impact from lower utilization of non-U.S. tax credits and the enactment of higher tax rates in the United Kingdom was essentially offset by the effect of non-recurring items, including the sale of non-U.S. assets. For the nine-month comparison, the increase in the effective tax rate was mainly due to lower utilization of non-U.S. tax credits and higher United Kingdom tax rates, which were partially offset by the effects of non-U.S. asset sales and foreign currency remeasurement impacts between periods.

Selected Operating Data

The following table presents a comparison of selected operating data:

Selected Operating Data(1)(2)


	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
U.S. Upstream
Net crude oil and natural gas liquids production (MBPD)			453			482			471			492
Net natural gas production (MMCFPD)(3)			1,260			1,255			1,276			1,317
Net oil-equivalent production (MBOEPD)			662			692			684			711
Sales of natural gas (MMCFPD)			5,812			6,091			5,767			5,956
Sales of natural gas liquids (MBPD)			16			22			16			23
Revenue from net production
Liquids ($/Bbl)		$	96.75		$	68.85		$	96.51		$	70.03
Natural gas ($/MCF)		$	4.14		$	4.06		$	4.18		$	4.47
International Upstream
Net crude oil and natural gas liquids production (MBPD)(4)			1,353			1,422			1,389			1,423
Net natural gas production (MMCFPD)(3)			3,496			3,748			3,663			3,723
Net oil-equivalent production (MBOEPD)(3)(4)			1,937			2,046			2,000			2,044
Sales of natural gas (MMCFPD)			4,303			4,597			4,375			4,486
Sales of natural gas liquids (MBPD)			24			28			24			28
Revenue from liftings
Liquids ($/Bbl)		$	102.82		$	69.67		$	101.59		$	70.39
Natural gas ($/MCF)		$	5.50		$	4.73		$	5.33		$	4.58
U.S. and International Upstream
Total net oil-equivalent production (MBOEPD)(3)(4)			2,599			2,738			2,684			2,755
U.S. Downstream
Gasoline sales (MBPD)(5)			670			696			658			716
Other refined product sales (MBPD)			582			647			609			651

Total refined product sales (MBPD)			1,252			1,343			1,267			1,367
Sales of natural gas liquids (MBPD)			144			135			144			139
Refinery input (MBPD)			897			880			883			895
International Downstream
Gasoline sales (MBPD)(5)			323			410			366			412
Other refined product sales (MBPD)			767			781			818			790
Share of affiliate sales (MBPD)			500			568			549			551

Total refined product sales (MBPD)			1,590			1,759			1,733			1,753
Sales of natural gas liquids (MBPD)			54			76			63			75
Refinery input (MBPD)			882			1,027			977			991

(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 conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil; MBOEPD — thousands of barrels of oil-equivalent per day.
(3) Includes natural gas consumed in operations (MMCFPD):
United States			72			59			71			63
International			477			500			482			474
(4) Includes: Canada — synthetic oil			44			27			40			22
Venezuela affiliate— synthetic oil			31			28			31			29
(5) Includes branded and unbranded gasoline.

Liquidity and Capital Resources

Cash, cash equivalents, time deposits and marketable securities totaled approximately $20.3 billion at September 30, 2011, up $3.3 billion from year-end 2010. Cash provided by operating activities in the first nine months of 2011 was $32.0 billion, compared with $23.1 billion in the year-ago period. Cash provided by operating activities during the first nine months of 2011 was sufficient to fund the $19.8 billion cash component of the company’s capital and exploratory program, pay $4.5 billion of dividends to shareholders and repurchase $3.0 billion of common stock. In addition, the company completed the $4.5 billion acquisition of Atlas Energy, Inc., funded from the company’s operating cash flows.

Dividends The company paid dividends of $4.5 billion to common stockholders during the first nine months of 2011. In October 2011, the company increased its quarterly dividend by 3.8 percent to 81 cents per common share payable in December 2011. This follows an increase of 8.3 percent announced in the second quarter 2011.

Debt and Capital Lease Obligations Chevron’s total debt and capital lease obligations were $9.7 billion at September 30, 2011, and $11.5 billion at December 31, 2010.

In September 2011, the company redeemed a $1.5 billion bond due to mature in March 2012.

The company’s debt and capital lease obligations due within one year, consisting primarily of commercial paper, redeemable long-term obligations and the current portion of long-term debt, totaled $5.5 billion at September 30, 2011 and $5.6 at December 31, 2010. Of these amounts, $5.3 billion was reclassified to long-term at September 30, 2011 and $5.4 billion at December 31, 2010, respectively. At September 30, 2011, settlement of these obligations was not expected to require the use of working capital within one year, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

At September 30, 2011, the company had $6.0 billion in committed credit facilities with various major banks, expiring in May 2013, which enable the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and can also 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 the London Interbank Offered Rate (LIBOR) or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at September 30, 2011. In addition, the company has an automatic shelf registration statement that expires in March 2013 for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company.

The major debt rating agencies routinely evaluate the company’s debt, and the company’s cost of borrowing can increase or decrease depending on these debt ratings. The company has outstanding public bonds issued by Chevron Corporation, Chevron Corporation Profit Sharing/Savings Plan Trust Fund, and Texaco Capital Inc. All of these securities are the obligations of, or guaranteed by, Chevron Corporation and are rated AA by Standard and Poor’s Corporation and Aa1 by Moody’s Investors Service. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 by Moody’s. All of these ratings denote high-quality, investment-grade securities.

The company’s future debt level is dependent primarily on results of operations, the capital program and cash that may be generated from asset dispositions. Based on its high-quality debt ratings, the company believes that it has substantial borrowing capacity to meet unanticipated cash requirements. The company also can modify capital spending plans during periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals to provide flexibility to continue paying the common stock dividend and maintain the company’s high-quality debt ratings.

Common Share Repurchase Program In July 2010, the Board of Directors approved an ongoing share repurchase program with no set term or monetary limits. The company expects to repurchase between $500 million and $2 billion of its common shares per quarter, at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. During third quarter 2011, the company purchased 12.7 million common shares for $1.25 billion. From the inception of the program through third quarter 2011, the company had purchased 38.8 million shares for $3.7 billion.

Noncontrolling Interests The company had noncontrolling interests of $785 million and $730 million at September 30, 2011 and December 31, 2010, respectively. Distributions to noncontrolling interests totaled $28 million during the first nine months of 2011.

Current Ratio — current assets divided by current liabilities, which indicates the company’s ability to repay its short-term liabilities with short-term assets. The current ratio was 1.6 at September 30, 2011 and 1.7 at December 31, 2010. The current ratio is adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis. At September 30, 2011, the book value of inventory was lower than replacement cost.

Debt Ratio — total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage. This ratio was 7.5 percent at September 30, 2011, and 9.8 percent at year-end 2010.

Pension Obligations At the end of 2010, the company estimated it would contribute $950 million to employee pension plans during 2011 (composed of $650 million for the U.S. plans and $300 million for the international plans). Through September 30, 2011, a total of $1.36 billion was contributed (including $1.14 billion to the U.S. plans). Total contributions for the full year are currently estimated to be $1.45 billion ($1.15 billion for the U.S. plans and $300 million for the international plans). Actual contribution amounts are dependent upon plan investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

Capital and Exploratory Expenditures Total expenditures, including the company’s share of spending by affiliates, were $20.8 billion in the first nine months of 2011, compared with $15.5 billion in the corresponding 2010 period. The amounts included the company’s share of affiliates’ expenditures of about $1 billion and $900 million in the 2011 and 2010 periods, respectively. Expenditures for upstream projects in the first nine months of 2011 were about $18.8 billion, representing 90 percent of the companywide total.

Capital and Exploratory Expenditures by Major Operating Area


	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
	(Millions of dollars)
United States
Upstream		$	2,060		$	736		$	6,341		$	2,268
Downstream			362			313			894			916
All Other			109			80			455			182

Total United States			2,531			1,129			7,690			3,366

International
Upstream			4,583			4,716			12,444			11,488
Downstream			297			264			663			676
All Other			2			3			5			7

Total International			4,882			4,983			13,112			12,171

Worldwide		$	7,413		$	6,112		$	20,802		$	15,537

Contingencies and Significant Litigation

personal-injury claims, may be filed in the future. The company’s ultimate exposure related to pending lawsuits and claims is not determinable, but could be material to net income in any one period. The company no longer uses MTBE in the manufacture of gasoline in the United States.

On February 14, 2011, the Provincial Court in Lago Agrio rendered an adverse judgment in the case. The Provincial Court rejected Chevron’s defenses to the extent the Court addressed them in its opinion. The judgment assessed approximately $8.6 billion in damages and approximately $0.9 billion as an award for the plaintiffs’ representatives. It also assessed an additional amount of approximately $8.6 billion in punitive damages unless the company issued a public apology within fifteen days of the judgment, which Chevron did not do. On February 17, 2011, the plaintiffs appealed the judgment, seeking increased damages, and on March 11, 2011, Chevron appealed the judgment seeking to have the judgment nullified. Chevron continues to believe the Court’s judgment is illegitimate and unenforceable in Ecuador, the United States and other countries. The company also believes the judgment is the product of fraud, and contrary to the legitimate scientific evidence. Chevron cannot predict the timing or ultimate outcome of the appeals process in Ecuador. Chevron will continue a vigorous defense of any imposition of liability. Because Chevron has no substantial assets in Ecuador, Chevron would expect enforcement actions as a result of this judgment to be brought in other jurisdictions. Chevron expects to contest any such actions.

Guarantees The company and its subsidiaries have certain other contingent liabilities with respect to guarantees, direct or indirect, of debt of affiliated companies or third parties. Under the terms of the guarantee arrangements, the company would generally be required to perform should the affiliated company or third party fail to fulfill its obligations under the arrangements. In some cases, the guarantee arrangements may have recourse provisions that would enable the company to recover any payments made under the terms of the guarantees from assets provided as collateral.

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.

Income Taxes Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions, examinations of tax

returns for certain prior tax years had not been completed as of September 30, 2011. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States — 2007, Nigeria — 2000, Angola — 2001 and Saudi Arabia — 2003.

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

New Accounting Standards

Refer to Note 13, on page 21 in the Notes to Consolidated Financial Statements, for information regarding new accounting standards.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the three months ended September 30, 2011, does not differ materially from that discussed under Item 7A of Chevron’s 2010 Annual Report on Form 10-K.

Item 4.

Controls and Procedures

(a) Evaluation of disclosure controls and procedures

The company’s management has evaluated, with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of the company’s disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the company’s disclosure controls and procedures were effective as of September 30, 2011.

(b) Changes in internal control over financial reporting

During the quarter ended September 30, 2011, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.

PART II

OTHER INFORMATION

Item 1.

Legal Proceedings

Government Proceedings As reported in the company’s annual report on Form 10-K for the year ended December 31, 2010, in March 2010, the United States Department of Justice indicated its intention to seek a civil penalty against the company’s service station operations in Puerto Rico for alleged violations of the Commonwealth of Puerto Rico’s underground storage tank regulations. The alleged violations included failure to test leak detectors, perform release monitoring and maintain compliance records. The company has settled the matter by agreeing to pay a civil penalty of $600,000.

As reported in the company’s annual report Form 10-K for the year ended December 31, 2010, the California Attorney General alleged violations of the State’s underground storage tank regulations at the company’s service stations in the State of California. The allegations were part of a state-wide enforcement action. The company has settled the matter, together with a matter brought by the Sacramento District Attorney, for $24.5 million, which included the payment of $16 million in civil fines and penalties, an agreement to reimburse the State of California costs of $3.5 million and to pay restitution of $2.5 million, with the remaining balance of $2.5 million being credited to Chevron for the prior completion of certain restitution payments and supplemental environmental projects.

The company has agreed to settle an administrative penalty proceeding brought by the Utah Department of Environmental Quality (DEQ) by agreeing to pay a civil penalty of $500,000 as a result of two crude oil spills in Salt Lake City, Utah. The first spill occurred in June 2010 and the second occurred in December 2010. In addition, the company agreed to pay Salt Lake City Corporation $1.0 million for “lost use” damages and $3 million to be used for restoration by the DEQ. The settlement is subject to a public review process, which is pending.

Item 1A.

Risk Factors

Chevron is a global energy company with a diversified business portfolio, a strong balance sheet, and a 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 three months ended September 30, 2011, does not differ materially from that set forth in Part I, Item 1A, of Chevron’s 2010 Annual Report on Form 10-K.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

CHEVRON CORPORATION

ISSUER PURCHASES OF EQUITY SECURITIES

Period

Total Number Of
Shares
Purchased(1)(2)

Average
Price Paid
per Share

Total Number of
Shares Purchased as
Part of Publicly
Announced Program

Maximum
Number of Shares
that May Yet Be
Purchased Under
the Program(2)

July 1-31, 2011

3,148,512

106.15

3,146,364

August 1-31, 2011

4,925,938

96.65

4,915,155

September 1-30, 2011

4,618,269

95.52

4,617,100

Total

12,692,719

98.60

12,678,619

(1)

Includes common shares repurchased during the three-month period ended September 30, 2011, from company employees for required personal income tax withholdings on the exercise of the stock options issued to management under long-term incentive plans and former Texaco Inc. and Unocal stock option plans. Also includes 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, 2011.

(2)

In July 2010, the Board of Directors approved an ongoing share repurchase program with no set term or monetary limits, under which common shares would be acquired by the company through open market purchases (some pursuant to a Rule 10b5-1 plan) at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. As of September 30, 2011, 38,785,274 shares had been acquired under this program for $3.75 billion.

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 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
(99.1)		Mine Safety Disclosure
(101.INS)		XBRL Instance Document
(101.SCH)		XBRL Schema Document
(101.CAL)		XBRL Calculation Linkbase Document
(101.DEF)		XBRL Definition Linkbase Document
(101.LAB)		XBRL Label Linkbase Document
(101.PRE)		XBRL Presentation Linkbase Document

Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

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/ MATTHEW J. FOEHR

Matthew J. Foehr, Vice President and Comptroller

(Principal Accounting Officer and
Duly Authorized Officer)

Date: November 3, 2011

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 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
(99.1)*		Mine Safety Disclosure
(101.INS)*		XBRL Instance Document
(101.SCH)*		XBRL Schema Document
(101.CAL)*		XBRL Calculation Linkbase Document
(101.DEF)*		XBRL Definition Linkbase Document
(101.LAB)*		XBRL Label Linkbase Document
(101.PRE)*		XBRL Presentation Linkbase Document

*	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.