UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

OR 

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to 

Commission File Number 001-00368

Chevron Corporation

(Exact name of registrant as specified in its charter)

Delaware 94-0890210 6001 Bollinger Canyon Road, 

San Ramon, California 94583-2324

(State or other jurisdiction of 

incorporation or organization)

(I.R.S. Employer 

Identification No.)

(Address of principal executive offices) (Zip Code)

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

Securities registered pursuant to Section 12 (b) of the Act:

Title of Each Class Name of Each Exchange 

on Which Registered

Common stock, par value $.75 per share New York Stock Exchange, Inc.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. 

Yes  No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. 

Yes o No 

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  No o

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  No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will

not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or

any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the

definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  Accelerated filer o Non-accelerated filer o

(Do not check if a smaller 

reporting company)

Smaller reporting company o

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was

last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal

quarter — $207,005,770,000 (As of June 29, 2012)

Number of Shares of Common Stock outstanding as of February 11, 2013 — 1,942,697,787

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2013 Annual Meeting and 2013 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection

with the company’s 2013 Annual Meeting of Stockholders (in Part III)

1
TABLE OF CONTENTS

ITEM PAGE NO.

PART I

1. Business 3

 General Development of Business 3

 Description of Business and Properties 4

 Capital and Exploratory Expenditures 4

 Upstream 4

 Downstream 24

 Other Businesses 26

 Web Site Access to SEC Reports 28

1A. Risk Factors 28

1B. Unresolved Staff Comments 30

2. Properties 30

3. Legal Proceedings 30

4. Mine Safety Disclosures 30

PART II

5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 31

6. Selected Financial Data 31

7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 31

7A. Quantitative and Qualitative Disclosures About Market Risk 31

8. Financial Statements and Supplementary Data 31

9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 32

9A. Controls and Procedures 32

9B. Other Information 32

PART III

10. Directors, Executive Officers and Corporate Governance 33

11. Executive Compensation 34

12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 34

13. Certain Relationships and Related Transactions, and Director Independence 34

14. Principal Accounting Fees and Services 34

PART IV

15. Exhibits, Financial Statement Schedules 35

Schedule II — Valuation and Qualifying Accounts 36

Signatures 37

EX-10.9 EX-24.9

EX-10.13 EX-31.1

EX-10.16 EX-31.2

EX-12.1 EX-32.1

EX-21.1 EX-32.2

EX-23.1 EX-95

EX-24.1 EX-99.1

EX-24.2 EX-101 INSTANCE DOCUMENT

EX-24.3 EX-101 SCHEMA DOCUMENT

EX-24.4 EX-101 CALCULATION LINKBASE DOCUMENT

EX-24.5 EX-101 LABELS LINKBASE DOCUMENT

EX-24.6 EX-101 PRESENTATION LINKBASE DOCUMENT

EX-24.7 EX-101 DEFINITION LINKBASE DOCUMENT

EX-24.8

1
CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION 

FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE 

PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This Annual Report on Form 10-K 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,” “forecasts,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “budgets,” “outlook” 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, many 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 chemicals 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 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 required by 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 28 through 30 in this report. In addition, such results

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.

2
PART I

Item 1. Business

General Development of Business

Summary Description of Chevron

Chevron Corporation,* a Delaware corporation, manages its investments in

subsidiaries and affiliates and provides administrative, financial,

management and technology support to U.S. and international subsidiaries

that engage in fully integrated petroleum operations, chemicals operations,

mining activities, power generation and energy services. Upstream

operations consist primarily of exploring for, developing and producing

crude oil and natural gas; processing, liquefaction, transportation and

regasification associated with liquefied natural gas; transporting crude oil

by major international oil export pipelines; transporting, storage and

marketing of natural gas; and a gas-to-liquids project. Downstream

operations consist primarily of refining crude oil into petroleum products;

marketing of crude oil and refined products; transporting 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.

 A list of the company’s major subsidiaries is presented on pages E-4 and

E-5. As of December 31, 2012, Chevron had approximately

62,000 employees (including about 3,700 service station employees).

Approximately 31,000 employees (including about 3,400 service station

employees), or 50 percent, were employed in U.S. operations.

Overview of Petroleum Industry

Petroleum industry operations and profitability are influenced by many

factors. Prices for crude oil, natural gas, petroleum products and

petrochemicals are generally determined by supply and demand. The

members of the Organization of Petroleum Exporting Countries (OPEC) are

typically the world’s swing producers of crude oil and their production

levels are a major factor in determining worldwide supply. Demand for

crude oil and its products and for natural gas is largely driven by the

conditions of local, national and global economies, although weather

patterns and taxation relative to

other energy sources also play a significant part. Laws and governmental

policies, particularly in the areas of taxation, energy and the environment

affect where and how companies conduct their operations and formulate

their products and, in some cases, limit their profits directly.

 Strong competition exists in all sectors of the petroleum and

petrochemical industries in supplying the energy, fuel and chemical needs

of industry and individual consumers. Chevron competes with fully

integrated, major global petroleum companies, as well as independent and

national petroleum companies, for the acquisition of crude oil and natural

gas leases and other properties and for the equipment and labor required to

develop and operate those properties. In its downstream business, Chevron

competes with fully integrated, major petroleum companies and other

independent refining, marketing, transportation and chemicals entities and

national petroleum companies in the sale or acquisition of various goods or

services in many national and international markets.

Operating Environment

Refer to pages FS-2 through FS-8 of this Form 10-K in Management’s

Discussion and Analysis of Financial Condition and Results of Operations

for a discussion of the company’s current business environment and

outlook.

Chevron’s Strategic Direction

Chevron’s primary objective is to create shareholder value and achieve

sustained financial returns from its operations that will enable it to

outperform its competitors. In the upstream, the company’s strategies are to

grow profitably in core areas, build new legacy positions and commercialize

the company’s equity natural gas resource base while growing a high-impact

global natural gas business. In the downstream, the strategies are to improve

returns and grow earnings across the value chain. The company also

continues to utilize technology across all its businesses to differentiate

performance, and to invest in profitable renewable energy and energy

efficiency solutions.

___________________________________

* Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. In

2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term “Chevron” and such terms as “the company,” “the corporation,” “our,”

“we” and “us” may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise they do not include

“affiliates” of Chevron — i.e., those companies accounted for by the equity method (generally owned 50 percent or less) or investments accounted for by the cost method. All of these

terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.

3
Description of Business and Properties

The upstream and downstream activities of the company and its equity

affiliates are widely dispersed geographically, with operations and projects*

in North America, South America, Europe, Africa, Asia and Australia.

Tabulations of segment sales and other operating revenues, earnings and

income taxes for the three years ending December 31, 2012, and assets as of

the end of 2012 and 2011 — for the United States and the company’s

international geographic areas — are in Note 10 to the Consolidated

Financial Statements beginning on page FS-36. Similar comparative data

for the company’s investments in and income from equity affiliates and

property, plant and equipment are in Notes 11 and 12 on pages FS-38

through FS-40.

Capital and Exploratory Expenditures

Total expenditures for 2012 were $34.2 billion, including $2.1 billion for

the company’s share of equity-affiliate expenditures. In 2011 and 2010,

expenditures were $29.1 billion and $21.8 billion, respectively, including

the company’s share of affiliates’ expenditures of $1.7 billion in 2011 and

$1.4 billion in 2010.

 Of the $34.2 billion in expenditures for 2012, 89 percent, or $30.4

billion, was related to upstream activities. Approximately 89 and 87 percent

was expended for upstream operations in 2011 and 2010, respectively.

International upstream accounted for about 72 percent of the worldwide

upstream investment in 2012, about 68 percent in 2011 and about 82

percent in 2010. These amounts exclude the acquisition of Atlas Energy,

Inc., in 2011.

 In 2013, the company estimates capital and exploratory expenditures will

be $36.7 billion, including $3.3 billion of spending by affiliates.

Approximately 90 percent of the total, or $33 billion, is budgeted for

exploration and production activities, with $25.5 billion, or about

70 percent, of this amount for projects outside the United States.

 Refer also to a discussion of the company’s capital and exploratory

expenditures on page FS-12.

Upstream

The table on the following page summarizes the net production of liquids

and natural gas for 2012 and 2011 by the company and its affiliates.

Worldwide oil-equivalent production was 2.610 million barrels per day,

down about 2 percent from 2011. The decrease was mainly associated with

normal field declines, the shut-in of the Frade Field in Brazil, and a major

planned turnaround at the Tengizchevroil facilities in Kazakhstan. The

start-up and ramp-up of several major capital projects — the Platong II

natural gas project in Thailand, the Usan and Agbami 2 projects in

Nigeria, and the Perdido, Tahiti 2 and Caesar/Tonga projects in the

U.S. Gulf of Mexico — partially offset the decrease in net production from

2011. Refer to the “Results of Operations” section beginning on page FS-6

for a detailed discussion of the factors explaining the 2010 through 2012

changes in production for crude oil and natural gas liquids, and natural

gas.

 The company estimates its average worldwide oil-equivalent production

in 2013 will be approximately 2.650 million barrels per day based on an

average Brent price of $112 per barrel in 2012. This estimate is subject to

many factors and uncertainties, including quotas that may be imposed by

OPEC, price effects on entitlement volumes, changes in fiscal terms or

restrictions on the scope of company operations, delays in project start-ups

and ramp-ups, 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-thanexpected declines in production from mature fields, or other disruptions to

operations. The longer-term outlook for 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. Refer to the “Review of Ongoing Exploration and Production

Activities in Key Areas,” beginning on page 9, for a discussion of the

company’s major crude oil and natural gas development projects.

___________________________________

* As used in this report, the term “project” may describe new upstream development activity, individual phases in a multiphase development, maintenance activities, certain existing

assets, new investments in downstream and chemicals capacity, investments in emerging and sustainable energy activities, and certain other activities. All of these terms are used for

convenience only and are not intended as a precise description of the term “project” as it relates to any specific governmental law or regulation.

4
Net Production of Crude Oil and Natural Gas Liquids and Natural Gas 1

Components of Oil-Equivalent

Crude Oil & Natural Gas

Oil-Equivalent (Thousands Liquids (Thousands of Natural Gas (Millions

of Barrels per Day) Barrels per Day) of Cubic Feet per Day)

2012 2011 2012 2011 2012 2011

United States 655 678 455 465 1,203 1,279

Other Americas

 Argentina 22 27 21 26 4 4

 Brazil 6 35 6 33 2 13

 Canada 69 70 68 69 4 4

 Colombia 36 39 — — 216 234

 Trinidad and Tobago 29 31 — — 173 183

 Total Other Americas 162 202 95 128 399 438

Africa

 Angola 137 147 128 139 53 50

 Chad 23 26 22 25 6 6

 Democratic Republic of the Congo 3 3 2 3 1 1

 Nigeria 269 260 242 236 165 142

 Republic of the Congo 19 23 17 21 13 10

 Total Africa 451 459 411 424 238 209

Asia

 Azerbaijan 28 28 26 26 10 10

 Bangladesh 94 74 2 2 550 434

 China 21 22 20 20 9 10

 Indonesia 198 208 158 166 236 253

 Kazakhstan 61 62 37 38 139 144

 Myanmar 16 14 — — 94 86

 Partitioned Zone2 90 91 86 88 21 20

 Philippines 24 25 4 4 120 126

 Thailand 243 209 67 65 1,060 867

 Total Asia 775 733 400 409 2,239 1,950

Australia 99 101 28 26 428 448

Europe

 Denmark 36 44 24 29 74 91

 Netherlands 9 7 2 2 42 31

 Norway 3 3 3 3 1 1

 United Kingdom 66 85 46 59 122 155

 Total Europe 114 139 75 93 239 278

Total Consolidated Companies 2,256 2,312 1,464 1,545 4,746 4,602

Equity Affiliates3 354 361 300 304 328 339

Total Including Affiliates4 2,610 2,673 1,764 1,849 5,074 4,941

1

 Includes synthetic oil: Canada, net 43 40 43 40 — —

Venezuelan affiliate, net 17 32 17 32 — —

2

 Located between Saudi Arabia and Kuwait.

3

 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan and Petroboscan, Petroindependiente and Petropiar in Venezuela.

4 Volumes include natural gas consumed in operations of 586 million and 582 million cubic feet per day in 2012 and 2011, respectively. Total “as sold” natural gas volumes were

4,488 million and 4,359 million cubic feet per day for 2012 and 2011, respectively.

5
Average Sales Prices and Production Costs per Unit of Production

Refer to Table IV on page FS-67 for the company’s average sales price per barrel of crude oil, condensate and natural gas liquids and per thousand cubic feet

of natural gas produced, and the average production cost per oil-equivalent barrel for 2012, 2011 and 2010.

Gross and Net Productive Wells

The following table summarizes gross and net productive wells at year-end 2012 for the company and its affiliates:

Productive Oil and Gas Wells at December 31, 2012

Productive Productive

Oil Wells Gas Wells

Gross Net Gross Net

United States 50,180 32,758 14,248 7,737

Other Americas 736 548 48 28

Africa 2,579 861 17 7

Asia 13,127 11,335 3,148 1,924

Australia 815 458 6 5 11

Europe 330 97 227 48

 Total Consolidated Companies 67,767 46,057 17,753 9,755

Equity Affiliates 1,300 456 7 2

 Total Including Affiliates 69,067 46,513 17,760 9,757

Multiple completion wells included above 876 602 407 369

Reserves

Refer to Table V beginning on page FS-67 for a tabulation of the company’s proved net crude oil and natural gas reserves by geographic area, at the beginning

of 2010 and each year-end from 2010 through 2012. Reserves governance, technologies used in establishing proved reserves additions, and major changes to

proved reserves by geographic area for the three-year period ended December 31, 2012, are summarized in the discussion for Table V. Discussion is also

provided regarding the nature of, status of and planned future activities associated with the development of proved undeveloped reserves. The company

recognizes reserves for projects with various development periods, sometimes exceeding five years. The external factors that impact the duration of a project

include scope and complexity, remoteness or adverse operating conditions, infrastructure constraints, and contractual limitations. 

 The net proved reserve balances at the end of each of the three years 2010 through 2012 are shown in the following table.

Net Proved Reserves at December 31

2012 2011 2010

Liquids — Millions of barrels

 Consolidated Companies 4,353 4,295 4,270

 Affiliated Companies 2,128 2,160 2,233

 Total Liquids 6,481 6,455 6,503

Natural Gas — Billions of cubic feet

 Consolidated Companies 25,654 25,229 20,755

 Affiliated Companies 3,541 3,454 3,496

 Total Natural Gas 29,195 28,683 24,251

Oil-Equivalent — Millions of barrels

 Consolidated Companies 8,629 8,500 7,729

 Affiliated Companies 2,718 2,736 2,816

 Total Oil-Equivalent 11,347 11,236 10,545

6
Acreage

At December 31, 2012, the company owned or had under lease or similar agreements undeveloped and developed crude oil and natural gas properties

throughout the world. The geographical distribution of the company’s acreage is shown in the following table.

Acreage at December 31, 2012

(Thousands of Acres)

Developed and

Undeveloped* Developed Undeveloped

Gross Net Gross Net Gross Net

United States 6,399 5,161 7,788 5,008 14,187 10,169

Other Americas 26,913 15,898 1,348 365 28,261 16,263

Africa 8,848 3,840 3,328 1,373 12,176 5,213

Asia 30,795 14,189 1,487 857 32,282 15,046

Australia 11,427 5,728 918 239 12,345 5,967

Europe 5,481 4,153 648 126 6,129 4,279

 Total Consolidated Companies 89,863 48,969 15,517 7,968 105,380 56,937

Equity Affiliates 938 430 259 102 1,197 532

 Total Including Affiliates 90,801 49,399 15,776 8,070 106,577 57,469

* The gross undeveloped acres that will expire in 2013, 2014 and 2015 if production is not established by certain required dates are 1,254, 3,629 and 3,141, respectively.

Delivery Commitments

The company sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Most contracts generally commit the

company to sell quantities based on production from specified properties, but some natural gas sales contracts specify delivery of fixed and determinable

quantities, as discussed below.

 In the United States, the company is contractually committed to deliver to third parties 192 billion cubic feet of natural gas through 2015. The company

believes it can satisfy these contracts through a combination of equity production from the company’s proved developed U.S. reserves and third-party

purchases. These commitments include a variety of pricing terms, including both indexed and fixed-price contracts.

 Outside the United States, the company is contractually committed to deliver a total of 791 billion cubic feet of natural gas to third parties from 2013

through 2015 for operations in Australia, Colombia, Denmark and the Philippines. These sales contracts contain variable pricing formulas that are generally

referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery. The company believes it can satisfy these

contracts from quantities available from production of the company’s proved developed reserves in these countries.

7
Development Activities

Refer to Table I on page FS-62 for details associated with the company’s development expenditures and costs of proved property acquisitions for 2012, 2011

and 2010. 

 The following table summarizes the company’s net interest in productive and dry development wells completed in each of the past three years, and the

status of the company’s development wells drilling at December 31, 2012. A “development well” is a well drilled within the proved area of a crude oil or

natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Development Well Activity

Wells Drilling Net Wells Completed

at 12/31/12 2012 2011 2010

Gross Net Prod. Dry Prod. Dry Prod. Dry

United States 78 45 941 6 909 9 634 7

Other Americas 13 6 50 — 37 — 32 —

Africa 10 4 23 — 29 — 33 —

Asia 75 35 566 15 549 15 445 15

Australia 8 4 — — — — — —

Europe 5 — 9 — 6 — 4 —

 Total Consolidated Companies 189 94 1,589 21 1,530 24 1,148 22

Equity Affiliates 6 3 26 — 25 — 8 —

 Total Including Affiliates 195 97 1,615 21 1,555 24 1,156 22

Exploration Activities

Refer to Table I on page FS-62 for detail on the company’s exploration expenditures and costs of unproved property acquisitions for 2012, 2011 and 2010.

 The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the last three years, and the

number of exploratory wells drilling at December 31, 2012. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unproved areas

and include delineation and appraisal wells, which are wells drilled to find a new reservoir in a field previously found to be productive of crude oil or natural

gas in another reservoir or to extend a known reservoir beyond the proved area.

Exploratory Well Activity

Wells Drilling Net Wells Completed

at 12/31/12 2012 2011 2010

Gross Net Prod. Dry Prod. Dry Prod. Dry

United States 11 8 4 — 5 1 1 1

Other Americas 2 1 8 — 1 — — 1

Africa 1 — 1 2 1 — 1 —

Asia 1 1 12 3 10 1 5 5

Australia 1 1 3 — 4 1 5 2

Europe 1 1 1 2 — 1 — —

 Total Consolidated Companies 17 12 29 7 21 4 12 9

Equity Affiliates — — — — 1 — — —

 Total Including Affiliates 17 12 29 7 22 4 12 9

8
Review of Ongoing Exploration and Production Activities in Key Areas

Chevron’s 2012 key upstream activities, some of which are also discussed

in Management’s Discussion and Analysis of Financial Condition and

Results of Operations, beginning on page FS-2, are presented below. The

comments include references to “total production” and “net production,”

which are defined under “Production” in Exhibit 99.1 on page E-11.

The discussion that follows references the status of proved reserves

recognition for significant long-lead-time projects not on production and for

projects recently placed on production. Reserves are not discussed for

exploration activities or recent discoveries that have not advanced to a

project stage, or for mature areas of production that do not have individual

projects requiring significant levels of capital or exploratory investment.

Amounts indicated for project costs represent total project costs, not the

company’s share of costs for projects that are less than wholly owned.

 Chevron has exploration and production activities in most of the world’s

major hydrocarbon basins. The company’s upstream strategy is to grow

profitably in core areas, build new legacy positions and commercialize the

company’s equity natural gas resource base while growing a high-impact

global natural gas business. The map above indicates Chevron’s primary

areas for exploration and production.

United States

Upstream activities in the United States are concentrated in California, the

Gulf of Mexico, Colorado, Louisiana, Michigan, New Mexico, Ohio,

Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. Average net

oil-equivalent production in the United States during 2012 was

655,000 barrels per day.

 In California, the company has significant production in the

San Joaquin Valley. In 2012, net daily production averaged 163,000 barrels

of crude oil, 70 million cubic feet of natural gas and 4,000 barrels of natural

gas liquids (NGLs). Approximately

86 percent of the crude oil production is considered heavy oil (typically

with API gravity lower than 22 degrees).

 During 2012, net daily production for the company’s combined interests

in the Gulf of Mexico shelf and deepwater areas, and the onshore fields in

the region, was 153,000 barrels of crude oil, 395 million cubic feet of

natural gas and 16,000 barrels of NGLs.

 Chevron was engaged in various exploration and development activities

in the deepwater Gulf of Mexico during 2012. The Jack and St. Malo fields

are located within 25 miles of each other and are being jointly developed.

Chevron has a 50 percent interest in the Jack Field, a 51 percent interest in

the St. Malo Field and a 50.7 percent interest in the production host facility.

Both fields are company operated. Drilling operations progressed during

2012, with five of 10 planned wells drilled. At the end of 2012, project

activities were more than 57 percent complete, with subsea and floating

production unit installation activities expected in second-half 2013. The

facility is planned to have a design capacity of 177,000 barrels of oilequivalent per day to accommodate production from the Jack/St. Malo

development, which is estimated to have maximum total daily production of

94,000 barrels of oil equivalent, plus production from a nearby third-party

field. Total project costs for the initial phase of development are estimated at

$7.5 billion and start-up is expected in 2014. The fields have an estimated

production life of 30 years. Proved reserves have been recognized for this

project.

 In 2012, an evaluation of additional development opportunities was

initiated for the Jack and St. Malo fields. Stage 2, the first phase of future

development work, is expected to include four additional development wells,

two each at the Jack and the St. Malo fields. Front-end engineering and

design (FEED) activities are planned to begin in mid-2013. At the end of

2012, proved reserves had not been recognized for the Jack/St. Malo Stage 2

project.

9
 Fabrication and development drilling continued in 2012 for the

60 percent-owned and operated Big Foot project. The development plan

includes a 15-slot drilling and production platform with water injection

facilities and a design capacity of 79,000 barrels of oil equivalent per day.

At the end of 2012, project activities were 68 percent complete, and topside

module installation is planned for mid-2013. First production is anticipated

in 2014. The field has an estimated production life of 20 years. Proved

reserves have been recognized for this project.

 Tahiti 2 is the second development phase for the 58 percent-owned and

operated Tahiti Field, and is designed to increase recovery and return

production to more than 100,000 barrels of crude oil per day. The project

includes two additional production wells, three water injection wells and

water injection facilities. Drilling commenced on the first production well in

early 2012, and water injection began in first quarter 2012. Start-up of the

first production well is expected by third quarter 2013. Proved reserves have

been recognized for the Tahiti 2 project, and the field has an estimated

production life of 30 years.

 The company has a 42.9 percent nonoperated working interest in the

Tubular Bells Field. Development drilling began in second quarter 2012,

and plans include three producing and two injection wells, with a subsea

tieback to a third-party production facility. First oil is anticipated in 2014,

and maximum total daily production is expected to reach 40,000 to 45,000

barrels of oil-equivalent. The field has an estimated production life of 25

years. The initial recognition of proved reserves for the project occurred in

2012.

 Chevron has a 20.3 percent nonoperated working interest in the Caesar

and Tonga area. First production occurred in first quarter 2012, and

maximum total daily production reached about 62,000 barrels of oilequivalent by year-end 2012. Drilling operations on the fourth development

well concluded in early 2013, and the well is expected to commence

production in second quarter 2013.

 The company has a 15.6 percent nonoperated working interest in the

Mad Dog II Project. FEED commenced in second quarter 2012 and a final

investment decision is expected in 2014. The project includes the

construction and installation of a new production and drilling spar facility

and is expected to add incremental maximum total daily production of

120,000 to 140,000 barrels of oil equivalent. At the end of 2012, proved

reserves had not been recognized for this project.

 In 2012, Chevron signed commercial agreements for the Stampede

project allowing for the joint development of the Knotty Head and Pony

fields. Chevron holds a 20 percent nonoperated working interest in this joint

development. The project is expected to enter FEED by mid-2013. At the end

of 2012, proved reserves had not been recognized for this project.

 Deepwater exploration activities in 2012 included participation in three

exploratory wells — one appraisal and two wildcats. Drilling began on an

appraisal well at the

43.8 percent-owned and operated Moccasin discovery in fourth quarter

2012. Drilling activities were placed on hold in early 2013 for equipment

repair and are expected to resume later this year. Moccasin and the

55 percent-owned and operated Buckskin discovery, located 12 miles

apart, could be jointly developed upon the successful completion of

additional appraisal drilling planned for 2013. A second Coronado wildcat

well began drilling in second quarter 2012, targeting the lower Tertiary

Wilcox formation. Drilling was completed in February 2013, and the results

are under evaluation. Chevron also had a 20 percent nonoperated working

interest in the Hummer Shallow wildcat well.

 Chevron added 15 leases to the deepwater portfolio as a result of awards

from the central Gulf of Mexico lease sale in mid-2012. In addition,

Chevron submitted the highest bids on 28 additional deepwater leases at the

western Gulf of Mexico lease sale in late 2012.

 Besides the activities connected with development and exploration

projects in the Gulf of Mexico, the company also has contracted liquefied

natural gas (LNG) offloading, storage and regasification capacity at the

Sabine Pass LNG facility and natural gas transportation capacity in a

third-party pipeline system connecting the terminal to the U.S. natural gas

pipeline grid.

10
 Company activities in the mid-continental United States include operated

and nonoperated interests in properties primarily in Colorado, New Mexico,

Oklahoma, Texas and Wyoming. During 2012, the company’s net daily

production in these areas averaged 90,000 barrels of crude oil, 600 million

cubic feet of natural gas and 29,000 barrels of NGL's.

 In West Texas, the company continues to pursue development of tight oil

and liquids-rich shale resources in the Midland Basin’s Wolfcamp play

and several plays in the Delaware Basin through use of advanced drilling

and completion technologies. Additional production growth is expected from

interests in these formations in future years. In October 2012, an

acquisition of more than 350,000 gross acres in New Mexico augmented the

company's leasehold position in the Delaware Basin and surrounding areas.

 The company holds leases in the Marcellus Shale and Utica Shale,

primarily located in southwestern Pennsylvania, Ohio, and West Virginia,

and in the Antrim Shale in Michigan. During 2012, the company's net daily

production in these areas averaged approximately 138 million cubic feet of

natural gas. In 2012, development of the Marcellus Shale proceeded at a

measured pace, focused on improving execution capability and reservoir

understanding. Activities in the Utica Shale during 2012 included

acquisition of regional seismic data in eastern Ohio to identify core areas.

The company commenced drilling on four exploratory wells during the year.

This initial activity was focused on acquiring data necessary for potential

future development. The company also holds a 49 percent interest in Laurel

Mountain Midstream, LLC, an affiliate that owns more than 1,200 miles of

natural gas gathering lines servicing the Marcellus.

Other Americas

“Other Americas” is composed of Argentina, Brazil, Canada, Colombia,

Suriname, Trinidad and Tobago, and Venezuela. Net oil-equivalent

production from these countries averaged 230,000 barrels per day during

2012, including the company’s share of synthetic oil production.

Canada: Chevron has interests in oil sands projects and shale acreage in

Alberta, shale acreage and an LNG project in British Columbia,

exploration, development and production projects offshore in the Atlantic

region, and exploration and discovered resource interests in the Beaufort Sea

region of the Northwest Territories. Average net oil-equivalent production

during 2012 was 69,000 barrels per day, composed of 25,000 barrels of

crude oil, 4 million cubic feet of natural gas and 43,000 barrels of synthetic

oil from oil sands.

 The company holds a 20 percent nonoperated working interest in the

Athabasca Oil Sands Project (AOSP). Oil sands are mined from both the

Muskeg River and the Jackpine mines and bitumen is extracted from the oil

sands and upgraded into synthetic oil. During 2012, ramp-up from the

AOSP Expansion 1 Project continued to boost production toward the total

daily design capacity of approximately 255,000 barrels. Additionally, a

final investment decision was reached in mid-2012 on the Quest Project, a

carbon capture and sequestration project that is designed to capture and

store more than one million tons annually of carbon dioxide produced by

bitumen processing at the AOSP by 2015.

 In February 2013, Chevron acquired a 50 percent-owned and operated

interest in the Kitimat LNG project and proposed Pacific Trail Pipeline, and

a 50 percent nonoperated working interest in 644,000 total acres in the Horn

River and Liard shale gas basins in British Colombia. The Kitimat project

is planned to include a two-train, 10.0 million-metric-ton-per-year LNG

facility, and at the time of acquisition, FEED activities were in progress.

11
 Chevron holds a 26.9 percent nonoperated working interest in the

Hibernia Field and a 23.6 nonoperated working interest in the unitized

Hibernia Southern Extension (HSE) offshore Atlantic Canada. The HSE

development is expected to increase the economic life of the Hibernia Field.

Fabrication of topside and subsea equipment progressed in 2012. Full

production start-up is expected in 2014. Proved reserves have been

recognized for the initial wells drilled.

 The company holds a 26.6 percent nonoperated working interest in the

heavy-oil Hebron Field, also offshore Atlantic Canada. The development

plan includes a concrete, gravity-based platform with a capacity of 150,000

barrels of crude oil per day. The maximum total daily crude oil production

is expected to be 134,000 barrels. FEED activities were completed in 2012,

and a final investment decision was made in December 2012. Project costs

are estimated at $14 billion. The project has an expected economic life of

30 years, and first oil is expected in 2017. The initial recognition of proved

reserves for the project occurred in 2012.

 During 2012, drilling continued on a multiwell program on the 100

percent-owned and operated leases in the Duvernay shale formation in

Alberta. The company also holds exploration licenses and leases in the

Flemish Pass and Orphan basins offshore Atlantic Canada and the

Beaufort Sea region of the Northwest Territories, including a 35.4 percent

nonoperated working interest in the offshore Amauligak discovery.

 In addition, Chevron holds interests in the Aitken Creek and Alberta

Hub natural gas storage facilities, which have aggregate total capacity of

approximately 100 billion cubic feet. These facilities are located in western

Canada near the Duvernay, Horn River, Liard and Montney shale gas

plays.

Greenland: In December 2012, Chevron relinquished its 29.2 percent

nonoperated working interest in Exploration License 2007/26, which

includes Block 4 offshore West Greenland.

Argentina: Chevron holds operated interests in four concessions in the

Neuquen Basin. Working interests range from 18.8 percent to 100 percent.

Net oil-equivalent production in 2012 averaged 22,000 barrels per day,

composed of 21,000 barrels of crude oil and 4 million cubic feet of natural

gas. During 2012, two exploratory wells targeting shale gas and tight oil

resources were drilled in the Vaca Muerta formation in the El Trapial

concession. In early 2013, a third exploratory well commenced drilling and

the results of the previous wells were under evaluation. Chevron plans to

drill three additional appraisal wells in 2013. The El Trapial concession

expires in 2032.

Brazil: Chevron holds working interests in three deepwater fields in the

Campos Basin: Frade (51.7 percent-owned and operated), Papa-Terra and

Maromba (37.5 percent and 30 percent nonoperated working interests,

respectively). Net oil-equivalent production in 2012 averaged 6,000 barrels

per day, composed of 6,000 barrels of crude oil and 2 million cubic feet of

natural gas.

 In March 2012, production was suspended as a precautionary measure

at the Frade Field while studies were conducted to better understand the

geology in the area. Production is expected to partially resume in 2013

subject to necessary regulatory approvals. The concession that includes the

Frade Field expires in 2025.

 During 2012, construction activities and development drilling continued

for the Papa-Terra project. The project includes a floating production,

storage and offloading vessel (FPSO) and a tension leg wellhead platform,

with a design capacity of 140,000 barrels of crude oil per day. First

production is expected in second-half 2013. Proved reserves have been

recognized for this project. Evaluation of the field development concept for

Maromba continued in 2012 with submission of an initial Plan of

Development to the authorities in September. At the end of 2012, proved

reserves had not been recognized for this project . These concessions expire

in 2032.

12
Colombia: The company operates the offshore Chuchupa and the onshore

Ballena and Riohacha natural gas fields as part of the Guajira Association

contract. In exchange, Chevron receives 43 percent of the production for the

remaining life of each field and a variable production volume based on prior

Chuchupa capital contributions. Daily net production averaged 216 million

cubic feet of natural gas in 2012.

Suriname: In November 2012, Chevron acquired a 50 percent nonoperated

working interest in Blocks 42 and 45 offshore Suriname. Under the

agreements, the company would assume the role of operator in the event of

commercial discoveries. In 2013, planned exploration activities include

seismic data acquisition and processing.

Trinidad and Tobago: The company has a 50 percent nonoperated

working interest in three blocks in the East Coast Marine Area offshore

Trinidad, which includes the Dolphin and Dolphin Deep producing natural

gas fields and the Starfish development. Net production in 2012 averaged

173 million cubic feet of natural gas per day. Development of the Starfish

Field commenced in third quarter 2012, and first gas is expected in 2014.

Natural gas from the project will supply existing contractual commitments.

Proved reserves have been recognized for this project. Chevron also holds a

50 percent-owned and operated interest in the Manatee Area of Block 6(d)

where the Manatee discovery comprises a single cross-border field with

Venezuela's Loran Field in Block 2. In 2012, work continued on maturing

commercial development concepts.

Venezuela: Chevron holds interests in two producing affiliates located in

western Venezuela and one producing affiliate in the Orinoco Belt. Chevron

has a 30 percent interest in the Petropiar affiliate that operates the Hamaca

heavy-oil production and upgrading project located in Venezuela’s Orinoco

Belt, a 39.2 percent interest in the Petroboscan affiliate that operates the

Boscan Field in the western part of the country, and a 25.2 percent interest

in the Petroindependiente affiliate that operates the LL-652 Field in Lake

Maracaibo. The company’s share of net oil-equivalent production during

2012 from these operations averaged 68,000 barrels per day, composed of

64,000 barrels of liquids and 27 million cubic feet of natural

gas.

 Chevron holds a 34 percent interest in the Petroindependencia affiliate

that is working toward commercialization of Carabobo 3, a heavy-oil project

located within the Carabobo Area of the Orinoco Belt. During 2012, work

continued on conceptual engineering for the potential development project.

 The company operates and has a working interest of 60 percent in

Block 2 in the Plataforma Deltana area offshore eastern Venezuela, which

includes the Loran Field. During 2012, work continued on maturing

commercial development concepts.

Africa

In Africa, the company is engaged in upstream activities in Angola, Chad,

Democratic Republic of the Congo, Liberia, Morocco, Nigeria, Republic of

the Congo, Sierra Leone and South Africa. Net oil-equivalent production in

Africa averaged 451,000 barrels per day during 2012.

Angola: Chevron holds company-operated working interests in offshore

Blocks 0 and 14 and nonoperated working interests in offshore Block 2

and the onshore Fina Sonangol Texaco (FST) area. Net production from

these operations in 2012 averaged 137,000 barrels of oil-equivalent per day.

 The company operates the 39.2 percent-owned Block 0, which averaged

98,000 barrels per day of net liquids production in 2012. The Block 0

concession extends through 2030.

13
 Work on the second development stage of the Mafumeira Field in

Block 0 continued in 2012. Mafumeira Sul, a project to develop the

southern portion of the field, reached a final investment decision in 2012.

Development plans include a central processing facility, two wellhead

platforms, subsea pipelines, and 34 producing and 16 water injection wells.

First production is planned for 2015, with maximum total production

expected to reach 110,000 barrels of crude oil and 10,000 barrels of liquefied

petroleum gas (LPG) per day. The project is estimated to cost $5.6 billion.

The initial recognition of proved reserves for this project occurred in 2012.

 A project to develop the Greater Vanza/Longui Area of Block 0 is

scheduled to enter FEED in second-half 2013. FEED activities continued

during 2012 on the south extension of the N’Dola Field development with a

final investment decision expected in 2014. The facility is planned to have a

design capacity of 28,000 barrels of crude oil per day. At the end of 2012,

proved reserves had not been recognized for these projects.

 Work continued in 2012 on the final stage of the Nemba Enhanced

Secondary Recovery Stage 1 and 2 Project in Block 0. Installation activities

are scheduled to begin in 2013, and project start-up is expected in early

2015. Maximum total production is expected to reach 13,000 barrels of oilequivalent per day. Proved reserves have been recognized for this project.

 Also in Block 0, drilling commenced on a post-salt/pre-salt dual

objective exploration well in Area A in late 2012 and was completed in early

2013. The results are under evaluation. An additional pre-salt exploration

well in Area A is planned for second-half 2013, along with one pre-salt and

one post-salt appraisal well in Area B.

 In the 31 percent-owned Block 14, net production in 2012 averaged

28,000 barrels of liquids per day. Development and production rights for

the various producing fields in Block 14 expire between 2023 and 2028.

 In June 2012, the project to develop the Lucapa Field in Block 14 entered

FEED. Development plans include an FPSO and 17 subsea wells. The

facility is planned to have a design capacity of 80,000 barrels of crude oil

per day. A final investment decision is expected in 2014. During the year,

development alternatives were evaluated for the Malange Field, and the

project is expected to enter FEED in mid-2013. At the end of 2012, proved

reserves had not been recognized for these projects.

 In addition to the exploration and production activities in Angola,

Chevron has a 36.4 percent interest in Angola LNG Limited, which will

operate an onshore natural gas liquefaction plant in Soyo, Angola. The plant

is designed to process 1.1 billion cubic feet of natural gas per day, with

expected average total daily sales of 670 million cubic feet of natural gas

and up to 63,000 barrels of NGLs. The plant reached mechanical

completion, and commissioning activities continued through 2012. The

first LNG shipment from the plant is expected to occur in second quarter

2013. The project is

estimated to cost $10 billion. The anticipated economic life of the project is

in excess of 20 years. Proved reserves have been recognized for the

producing operations associated with this project.

 The company also holds a 38.1 percent interest in a pipeline project that

is designed to transport up to 250 million cubic feet of natural gas per day

from Block 0 and Block 14 to the Angola LNG plant. Construction on the

project continued in 2012, and the project is expected to be completed in

2014.

Angola-Republic of the Congo Joint Development Area: Chevron

operates and holds a 31.3 percent interest in the Lianzi development zone,

located in an area shared equally by Angola and the Republic of the Congo.

A final investment decision for the Lianzi development project was reached

in July 2012. The project scope includes four producing wells and three

water injection wells with a subsea tieback to an existing platform in Block

14. First production is anticipated in 2015, and maximum total daily

production is expected to be 46,000 barrels of crude oil. The initial

recognition of proved reserves for the project occurred in 2012.

Democratic Republic of the Congo: Chevron has a 17.7 percent

nonoperated working interest in an offshore concession. Daily net

production in 2012 averaged 3,000 barrels of oil-equivalent.

Republic of the Congo: Chevron has a 31.5 percent nonoperated working

interest in the Haute Mer permit areas (Nkossa, Nsoko and Moho-Bilondo)

and a 29.3 percent nonoperated working interest in the Kitina permit area,

all of which are offshore. The licenses for Kitina, Nsoko, Nkossa and

Moho-Bilondo expire in 2014, 2018, 2027 and 2030, respectively. Net

production averaged 19,000 barrels of oil-equivalent per day in 2012.

 FEED activities for the Moho Nord project, located in the Moho-Bilondo

development area, continued in 2012. The project includes a new facilities

hub and a subsea tieback to the existing Moho-Bilondo floating production

unit. Maximum total daily production is expected to be 127,000 barrels of

crude oil per day. A final investment decision is expected in first quarter

2013 and start-up is planned for 2015. At the end of 2012, proved reserves

had not been recognized for this project.

Chad/Cameroon: Chevron has a 25 percent nonoperated working interest

in crude oil producing operations in southern Chad, and an approximate

21 percent interest in two affiliates that own an export pipeline that

transports crude oil to the coast of Cameroon. Average daily net production

from the Chad fields in 2012 was 23,000 barrels of oil-equivalent. The

Chad producing operations are conducted under a concession that expires in

2030.

14
Nigeria: Chevron holds a 40 percent interest in 13 concessions,

predominantly in the onshore and near-offshore regions of the Niger Delta.

The company operates under a joint-venture arrangement in this region with

the Nigerian National Petroleum Corporation, which owns a 60 percent

interest. The company also owns varying interests in four operated and six

nonoperated deepwater blocks. In 2012, the company’s net oil-equivalent

production in Nigeria averaged 269,000 barrels per day, composed of

238,000 barrels of crude oil, 165 million cubic feet of natural gas and 4,000

barrels of LPG.

 Chevron operates and holds a 67.3 percent interest in the Agbami Field,

located in deepwater Oil Mining Lease (OML) 127 and OML 128. During

2012, drilling continued on a 10-well, Phase 2 development program,

Agbami 2, that is expected to offset field decline and maintain plateau

production. The first well in this program commenced production in second

quarter 2012. The leases that contain the Agbami Field expire in 2023 and

2024.

 The company holds a 30 percent nonoperated working interest in the

deepwater Usan project in OML 138. Production commenced in first

quarter 2012, and total daily production at year-end 2012 was 81,000

barrels of crude oil and 3 million cubic feet of natural gas. The facilities

have a maximum total production capacity of 180,000 barrels of crude oil

per day. The production-sharing contract (PSC) expires in 2023.

 Also in the deepwater area, the Aparo Field in OML 132 and OML 140

and the third-party-owned Bonga SW Field in OML 118 share a common

geologic structure and are planned to be jointly developed. The project is

expected to enter FEED in 2013. At the end of 2012, no proved reserves were

recognized for this project.

 In the Niger Delta, the company reached a final investment decision in

early 2013 on the Dibi Long-Term Project that is designed to rebuild the Dibi

facilities and replace the Early Production System facility. The facilities are

planned to have a maximum production capacity of 70,000 barrels of crude

oil per day, and start-up is expected in 2016.

 Also in the Niger Delta, ramp-up activity continued at the Escravos Gas

Plant (EGP). During 2012, construction continued on Phase 3B of the EGP

project, which is designed to gather 120 million cubic feet of natural gas per

day from eight offshore fields and to compress and transport the natural gas

to onshore facilities. The Phase 3B project is expected to be completed in

2016. Proved reserves associated with this project have been recognized.

 The 40 percent-owned and operated Sonam Field Development is

designed to process natural gas through EGP, deliver 215 million cubic feet

of natural gas per day to the domestic market and produce a total of

30,000 barrels of liquids per day. First production is expected in 2016.

Proved reserves have been recognized for the project.

 Chevron has a 75 percent-owned and operated interest in a gas-to-liquids

facility at Escravos that is being developed with the Nigerian National

Petroleum Corporation. The 33,000-barrel-per-day facility is designed to

process 325 million cubic feet per day of natural gas supplied from the

Phase 3A expansion of EGP. As of early 2013, overall work on the project

was more than 89 percent complete and start-up is planned for late 2013.

The estimated cost of the plant is $9.5 billion.

 The company has a 40 percent-owned and operated interest in the

Onshore Asset Gas Management project that is designed to restore

approximately 125 million cubic feet per day of natural gas production

from certain onshore fields that have been shut in since 2003 due to civil

unrest. Construction was completed in third quarter 2012, and start-up

commenced in late 2012.

 In deepwater exploration, the company has a 27 percent nonoperated

working interest in Oil Prospecting License (OPL) 223 where an exploration

well was drilled in third quarter 2012. In addition, Chevron operates and

holds a 95 percent interest in the deepwater Nsiko discovery in OML 140.

Additional exploration activities are planned for 2013 and 2014.

 Shallow-water exploration activities in 2012 included reprocessing 3-D

seismic data from OML 86 and OML 88 and regional mapping activities.

 With a 36.7 percent interest, Chevron is the largest shareholder in the

West African Gas Pipeline Company Limited affiliate, which owns and

operates the 421-mile West African Gas Pipeline. The pipeline supplies

Nigerian natural gas to customers in Benin, Ghana and Togo for industrial

applications and power generation and has the capacity to transport

170 million cubic feet per day.

Liberia: Chevron operates three deepwater blocks off the coast of Liberia.

In July 2012, the company farmed down its interest from 70 percent to 45

percent in these blocks. Exploration wells were drilled in blocks LB-11 and

LB-12 during 2012. In 2013, the company plans to mature drilling

prospects based on the evaluation of 2012 drilling results and 3-D seismic

data.

15
Morocco: In early 2013, the company entered into agreements to acquire a

75 percent operated interest in three deepwater areas offshore Morocco. The

areas, Cap Rhir Deep, Cap Cantin Deep and Cap Walidia Deep, encompass

approximately 7.2 million acres. Once the award is finalized, acquisition of

seismic data is planned.

Sierra Leone: In September 2012, the company announced that it had

been awarded operatorship and a 55 percent interest in a concession off the

coast of Sierra Leone. The concession contains two deepwater blocks, with

a combined area of approximately 1.4 million acres. Acquisition of 2-D

seismic data is planned for 2013.

South Africa: In December 2012, the company entered into an agreement to

seek shale gas exploration opportunities in the Karoo Basin in South Africa.

This agreement allows Chevron and its partner to work together over a fiveyear period to obtain exploration permits in the 151 million-acre basin.

Asia

In Asia, the company is engaged in upstream activities in Azerbaijan,

Bangladesh, Cambodia, China, Indonesia, Kazakhstan, the Kurdistan

Region of Iraq, Myanmar, the Partitioned Zone located between Saudi

Arabia and Kuwait, the Philippines, Russia, Thailand, and Vietnam.

During 2012, net oil-equivalent production averaged 1,061,000 barrels per

day.

Azerbaijan: Chevron holds an 11.3 percent nonoperated working interest

in the Azerbaijan International Operating Company (AIOC), which

produces crude oil from the Azeri-Chirag-Gunashli (ACG) project. The

company’s daily net

production from AIOC averaged 28,000 barrels of oil-equivalent in 2012.

AIOC operations are conducted under a PSC that expires in 2024.

 During 2012, construction progressed on the next development phase of

the ACG project, which will further develop the deepwater Gunashli Field.

The total estimated cost of the project is $6 billion, with an incremental

targeted maximum total daily production of 103,000 barrels of oilequivalent. Production is expected to begin in late 2013. Proved reserves

have been recognized for this project.

 Chevron also has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan

(BTC) affiliate, which owns and operates a crude oil export pipeline from

Baku, Azerbaijan, through Georgia to Mediterranean deepwater port

facilities at Ceyhan, Turkey. The BTC Pipeline has a capacity of

1.2 million barrels per day and transports the majority of ACG production.

Another production export route for crude oil is the Western Route Export

Pipeline, wholly owned and operated by AIOC, with capacity to transport

100,000 barrels per day from Baku, Azerbaijan, to a marine terminal at

Supsa, Georgia.

Kazakhstan: Chevron participates in two major upstream developments in

western Kazakhstan. The company holds a 50 percent interest in the

Tengizchevroil (TCO) affiliate, which is operating and developing the

Tengiz and Korolev crude oil fields under a concession that expires in 2033.

Chevron’s net oil-equivalent production in 2012 from these fields averaged

286,000 barrels per day, composed of 218,000 barrels of crude oil,

301 million cubic feet of natural gas and 18,000 barrels of NGLs. During

2012, the majority of TCO’s crude oil production was exported through the

Caspian Pipeline Consortium (CPC) pipeline that runs from Tengiz in

Kazakhstan to tanker-loading facilities at Novorossiysk on the Russian

coast of the Black Sea. The balance was exported via rail to Black Sea

ports.

 In 2012, FEED activities were initiated for three projects. The Wellhead

Pressure Management Project is designed to maintain production capacity

and extend the production plateau from existing assets. The Capacity and

Reliability Project is designed to reduce facility bottlenecks and increase

plant efficiency and reliability. The Future Growth Project is designed to

increase total daily crude oil production by 250,000 to 300,000 barrels of oilequivalent and to increase the ultimate recovery of the reservoir. The project

will expand the utilization of sour gas injection technology proven in existing

operations. The final investment decisions on these projects are planned for

late 2013. At the end of 2012, proved reserves have only been recognized for

the Wellhead Pressure Management Project.

 Also at TCO, start-up commenced on the Sulfur Expansion Project in

December 2012. This project is designed to eliminate routine additions to

sulfur inventory.

16
 In June 2012, the company's nonoperated working interest in the

Karachaganak Field was reduced from 20 percent to 18 percent as a result

of a 2011 agreement with the Republic of Kazakhstan government.

Operations and development of the field are conducted under a PSC that

expires in 2038. During 2012, Karachaganak net oil-equivalent production

averaged 61,000 barrels per day, composed of 37,000 barrels of liquids and

139 million cubic feet of natural gas. Access to the CPC and AtyrauSamara (Russia) pipelines enabled approximately 35,000 net barrels per day

of Karachaganak liquids to be exported and sold at world-market prices

during 2012. The remaining liquids were sold into local and Russian

markets. During 2012, work continued on identifying the optimal scope for

the future expansion of the field. At the end of 2012, proved reserves had

not been recognized for any further expansion.

Kazakhstan/Russia: Chevron has a 15 percent interest in the CPC

affiliate. During 2012, CPC transported an average of approximately

657,000 barrels of crude oil per day, including 590,000 barrels per day

from Kazakhstan and 67,000 barrels per day from Russia. During 2012,

work continued on the 670,000-barrel-per-day expansion of the pipeline

capacity with the mechanical completion of the offshore loading system.

The $5.4 billion project is expected to be implemented in three phases, with

capacity increasing progressively until reaching maximum capacity of

1.4 million barrels per day in 2016. The first increase in capacity of

400,000 barrels per day is expected in 2014.

Turkey: In December 2012, Chevron relinquished its 50 percent interest in

License 3921 in the Black Sea.

Bangladesh: Chevron holds a 98 percent interest in two operated PSCs

covering Block 12 (Bibiyana) and Blocks 13 and 14 (Jalalabad and

Moulavi Bazar fields). The rights to produce from Jalalabad expire in 2024,

from Moulavi Bazar in 2028 and from Bibiyana in 2034. Net oil-equivalent

production from these operations in 2012 averaged 94,000 barrels per day,

composed of 550 million cubic feet of natural gas and 2,000 barrels of

liquids.

 In April 2012, start-up of the Muchai compression project was achieved.

This project supports additional natural gas production capacity of 80

million cubic feet per day from the Bibiyana, Jalalabad and Moulavi Bazar

fields. The Bibiyana Expansion project achieved a final investment decision

in July 2012. The project scope includes a gas plant expansion, additional

development drilling and an enhanced liquids recovery unit, and is expected

to increase total maximum daily production by more than 300 million cubic

feet of natural gas and 4,000 barrels of condensate. First production is

expected in 2014. The initial recognition of proved reserves for this

expansion project occurred in 2012.

Cambodia: Chevron owns a 30 percent interest and operates the

1.2 million-acre Block A, located in the Gulf of Thailand. In 2012, the

company progressed discussions on the production permit for development

of Block A. The planned development consists of a wellhead platform and a

floating storage and offloading vessel (FSO). A final investment decision is

pending resolution of commercial terms. At the end of 2012, proved reserves

had not been recognized for the project.

Myanmar: Chevron has a 28.3 percent nonoperated working interest in a

PSC for the production of natural gas from the Yadana and Sein fields,

within Blocks M5 and M6, in the Andaman Sea. The PSC expires in

2028. The company also has a 28.3 percent nonoperated interest in a

pipeline company that transports the natural gas to the Myanmar-Thailand

border for delivery to power plants in Thailand. The company’s average net

natural gas production in 2012 was 94 million cubic feet per day.

Thailand: Chevron has operated and nonoperated working interests in

multiple offshore blocks in the Gulf of Thailand. The company’s net oilequivalent production in 2012 averaged 243,000 barrels per day, composed

of 67,000 barrels of crude oil and condensate and 1.1 billion cubic feet of

natural gas. The company’s natural gas production is sold to the domestic

market under long-term sales contracts.

 The company holds operated interests in the Pattani Basin with

ownership interests ranging from 35 percent to 80 percent. Concessions for

producing areas within this basin expire between 2020 and 2035. Chevron

has a 16 percent nonoperated working interest in the Arthit Field located in

the Malay Basin. Concessions for the producing areas within this basin

expire between 2036 and 2040.

17
 During 2012, the company drilled six exploration wells in the Pattani

Basin, and four were successful. The company also holds exploration

interests in the Thailand-Cambodia overlapping claim area that are inactive,

pending resolution of border issues between Thailand and Cambodia.

Vietnam: Chevron is the operator of two PSCs in the Malay Basin off the

southwest coast of Vietnam. The company has a 42.4 percent interest in a

PSC that includes Blocks B and 48/95, and a 43.4 percent interest in a

PSC for Block 52/97.

The Block B Gas Development Project is designed to produce natural gas

from the Malay Basin for delivery to state-owned Petrovietnam. The project

includes installation of wellhead and hub platforms, an FSO, a central

processing platform and a pipeline to shore. FEED continued during 2012.

Maximum total daily production is expected to be 490 million cubic feet of

natural gas and 4,000 barrels of condensate. A final investment decision for

the development is pending resolution of commercial terms. At the end of

2012, proved reserves had not been recognized for the development project.

 During 2012, the company drilled two exploratory wells in Block

52/97, and both were successful.

China: Chevron has operated and nonoperated working interests in several

areas in China. The company’s net oil-equivalent production in 2012

averaged 21,000 barrels per day, composed of 20,000 barrels of crude oil

and condensate and 9 million cubic feet of natural gas.

 The company operates and holds a 49 percent interest in the

Chuandongbei PSC, located in the onshore Sichuan Basin. The full

development includes two new sour-gas processing plants with an aggregate

inlet design capacity of 740 million cubic feet per day, connected by a

natural gas gathering system to five fields. During 2012, the company

continued construction of the first natural gas processing plant, and site

preparation commenced for the second natural gas processing plant. The

initial plant, with an expected maximum total production of 258 million

cubic feet per day, is targeted for mechanical completion at the end of 2013.

Planned maximum total natural gas production is 558 million cubic feet per

day, and the total project cost is estimated to be $6.4 billion. Proved

reserves have been recognized for this project. The PSC for Chuandongbei

expires in 2037.

 The company holds a 59.2 percent-owned and operated interest in

deepwater Block 42/05 in the South China Sea, which covers exploratory

acreage of approximately 1.3 million acres. During 2012, the company

drilled two exploration wells in South China Sea deepwater Blocks 53/30

and 64/18, and both were unsuccessful. In November 2012, the company

relinquished its interest in deepwater Blocks 53/30 and 64/18.

Additional 3-D seismic data was acquired over Block 42/05, and further

exploration drilling is under evaluation. In 2012, Chevron entered into an

agreement to acquire a 100 percent-owned and operated interest in shallowwater Blocks 15/10 and 15/28, which cover approximately 1.4 million

exploratory acres. Government approval is expected in first-half 2013, and a

3-D seismic survey is expected to commence in mid-2013.

 During 2012, the company drilled an initial exploratory well for shale

gas in the Qiannan Basin. Evaluation of the well continues in early 2013.

Additional drilling is planned for 2013.

 The company also has nonoperated working interests of 32.7 percent in

Blocks 16/08 and 16/19 in the Pearl River Mouth Basin and nonoperated

working interests of 24.5 percent in the QHD 32-6 Field and 16.2 percent

in Block 11/19 in the Bohai Bay.

Philippines: The company holds a 45 percent nonoperated working interest

in the Malampaya natural gas field located 50 miles offshore Palawan

Island. Net oil-equivalent production in 2012 averaged 24,000 barrels per

day, composed of 120 million cubic feet of natural gas and 4,000 barrels of

condensate. During 2012, plans progressed on Malampaya Phase 2 to drill

two additional infill wells and to add depletion compression facilities. Startup is planned for 2014. Proved reserves have been recognized for this

project.

18
 Chevron also develops and produces geothermal resources in southern

Luzon, which supply steam to third-party, 637-megawatt power generation

facilities. During fourth quarter 2012, Chevron sold 60 percent of its

interest in these geothermal operations in order to secure a 25-year

geothermal operating contract with the Philippine government for the

continued development and operation of the steam fields. Chevron also has

a 90 percent-owned and operated interest in the Kalinga geothermal prospect

area in northern Luzon and is in the early phase of geological and

geophysical assessments.

Indonesia: Chevron holds operated and nonoperated working interests in

Indonesia. The company has 100 percent-owned and operated interests in

the Rokan and Siak PSCs onshore Sumatra. Chevron also operates four

PSCs in the Kutei Basin, located offshore East Kalimantan. These interests

range from 62 percent to 92.5 percent. Chevron also has 51 percent

operated working interests in two exploration blocks in western Papua, West

Papua I and West Papua III, and a 25 percent nonoperated working interest

in a joint venture in Block B in the South Natuna Sea.

 The company’s net oil-equivalent production in 2012 from its interests

in Indonesia averaged 198,000 barrels per day, composed of

158,000 barrels of liquids and 236 million cubic feet of natural gas. The

largest producing field is Duri, located in the Rokan PSC. Duri has been

under steamflood since 1985 and is one of the world’s largest steamflood

developments. The North Duri Development is divided into multiple

expansion areas. Construction began on the Duri Area 13 expansion project

in fourth quarter 2012. First production is scheduled for late 2013, and

maximum total daily production of 17,000 barrels of crude oil is expected to

be reached in 2016. The Rokan PSC expires in 2021.

 During 2012, two deepwater development projects in the Kutei Basin

progressed under a single plan of development. In the first of these projects,

Chevron completed FEED for the Gendalo-Gehem deepwater natural gas

project, and a final investment decision is expected during 2014. The project

includes two separate hub developments, natural gas and condensate

pipelines, and an onshore receiving facility. Maximum total daily

production from the project is expected to be about 1.1 billion cubic feet of

natural gas and 31,000 barrels of condensate. Gas from the project is

expected to be used

domestically and for LNG export. The company’s working interest is

approximately 63 percent. At the end of 2012, proved reserves had not been

recognized for this project.

 In the second of these projects, the company requested bids for all major

contracts for the Bangka deepwater natural gas project. A final investment

decision is expected in 2013. The project scope includes a subsea tieback to

a floating production unit, and maximum total daily production is expected

to be about 114 million cubic feet of natural gas and 4,000 barrels of

condensate. The company’s working interest is 62 percent. At year-end

2012, proved reserves had not been recognized for this project.

 In Sumatra, four exploration wells were drilled. Two wells were

successful and the results for two wells are under evaluation in early 2013.

Appraisal and exploration drilling is planned for 2013. In the West Papua

exploration blocks, which are in close proximity to a third-party LNG

facility, seismic data acquisition and processing was completed for West

Papua I in 2012 and is planned for completion for West Papua III in 2013.

 In West Java, the company operates and holds a 95 percent interest in

the Darajat geothermal field, which supplies steam to a power plant with a

total operating capacity of 259 megawatts. Chevron also operates and holds

a 100 percent interest in the Salak geothermal field in West Java, which

supplies steam to a power plant with a total operating capacity of 377

megawatts. In Sumatra, Chevron operates and holds a 95 percent interest in

the North Duri Cogeneration Plant, supplying up to 300 megawatts of power

to the company's Sumatra operations and steam in support of the Duri

steamflood project. In the Suoh-Sekincau prospect area of Sumatra, the

company holds a 95 percent-owned and operated interest in a license to

explore and develop a geothermal prospect.

19
Kurdistan Region of Iraq: In July 2012, the company announced the

acquisition of an 80 percent-owned and operated interest in two PSCs

covering the Rovi and Sarta blocks in the Kurdistan Region of Iraq. The

blocks cover a combined area of approximately 232,000 acres.

Partitioned Zone (PZ): Chevron holds a concession to operate the

Kingdom of Saudi Arabia's 50 percent interest in the petroleum resources in

the onshore area of the PZ between Saudi Arabia and Kuwait. The

concession expires in 2039.

 During 2012, the company's average net oil-equivalent production was

90,000 barrels per day, composed of 86,000 barrels of crude oil and 21

million cubic feet of natural gas. During 2012, the company continued a

steam injection pilot project in the First Eocene carbonate reservoir that was

initiated in 2009. A project to expand the steam injection pilot to the Second

Eocene reservoir is expected to enter FEED by late 2013. Development

planning also continued during 2012 on a full-field steamflood application

in the Wafra Field. The Wafra Steamflood Stage 1 Project is expected to

enter FEED in 2014. At the end of 2012, proved reserves had not been

recognized for any of these steamflood developments.

 Also in 2012, FEED activities continued on the Central Gas Utilization

Project. The project is intended to increase natural gas utilization and

eliminate routine flaring. A final investment decision is expected in 2014. At

year-end 2012, proved reserves had not been recognized for this project. 

Australia

In Australia, the company’s upstream efforts are concentrated off the

northwest coast. During 2012, the average net oil-equivalent production

from Australia was 99,000 barrels per day.

 Chevron holds a 47.3 percent ownership interest across most of the

Greater Gorgon Area and is the operator of the Gorgon Project, which

combines the development of the Gorgon and nearby Io/Jansz natural gas

fields. The development includes a three-train, 15.6 million-metric-ton-peryear LNG facility, a carbon sequestration project and a domestic natural

gas plant. Maximum total daily production from the project is expected to

reach approximately 2.6 billion cubic feet of natural gas and 20,000 barrels

of condensate. Start-up of the first train is expected in late 2014, leading to

the first LNG cargo in first quarter 2015. Total estimated project costs for

the first phase of development are $52 billion. Proved reserves have been

recognized for this project. The project's estimated economic life exceeds 40

years from the time of start-up.

20
 Work on the Gorgon project continued during 2012. As of year-end

2012, more than 55 percent of the project activities had been completed.

Key milestones achieved in 2012 were the arrival and installation of the first

LNG plant modules, subsea wellhead trees and subsea pipelines. The

development drilling program also progressed during 2012.

 Chevron has signed binding, long-term LNG Sales and Purchase

Agreements with six Asian customers for delivery of about 4.8 million

metric tons of LNG per year, which brings delivery commitments to about

65 percent of Chevron’s share of LNG from this project. Discussions

continue with potential customers to increase long-term sales to 85 percent

of Chevron’s net LNG offtake. Chevron also has binding long-term

agreements for delivery of about 65 million cubic feet per day of natural gas

to Western Australian natural gas consumers starting in 2015, and the

company continues to market additional natural gas quantities from the

Gorgon Project.

 An expansion project to develop a fourth train at the Gorgon LNG

facility is expected to enter FEED in late 2013. At the end of 2012, proved

reserves had not been recognized for the fields associated with this project.

 Chevron is the operator of the Wheatstone Project, which includes a twotrain, 8.9 million-metric-ton-per-year LNG facility and a domestic gas plant

located at Ashburton North, along the northwest coast of Australia. The

company plans to supply natural gas to the facilities from three companyoperated licenses, containing the Wheatstone Field and nearby Iago Field.

Maximum total daily production from these and third-party fields is

expected to be about 1.6 billion cubic feet of natural gas and 30,000 barrels

of condensate. Start-up of the first train is expected in 2016. Total estimated

project costs for the first phase of development are $29 billion. Proved

reserves have been recognized for this project. The project's estimated

economic life exceeds 30 years from the time of start-up.

 In 2012, construction and fabrication activities progressed, with a focus

on delivering site infrastructure and key components of the platform and

subsea equipment. Chevron signed additional commercial agreements that

decreased Chevron's interest in the offshore licenses to 80.2 percent and in

the LNG facilities to 64.1 percent. The company also executed agreements

with Asian customers for the delivery of additional volumes of LNG. As of

year-end 2012, more than 80 percent of Chevron’s equity LNG offtake was

covered under long-term agreements with customers in Asia. In addition, the

company has begun marketing its equity share of natural gas of

approximately 120 million cubic feet per day to Western Australia natural

gas consumers.

 During 2012 and early 2013, the company announced seven natural gas

discoveries in the Carnarvon Basin. These include natural gas discoveries

at the 47.3 percent-owned and operated Pontus prospect in Block WA-37-L,

the 50 percent-owned and operated Satyr prospect in Block WA-374-P, the

50 percent-owned and operated Pinhoe prospect in Block WA-383-P, the 50

percent-owned and operated Arnhem prospect in Block

WA-364-P, and the 50 percent-owned and operated Kentish Knock South

prospect in Block WA-365-P. These discoveries are expected to contribute to

potential expansion opportunities at company-operated LNG facilities.

 Chevron has a 16.7 percent nonoperated working interest in the North

West Shelf (NWS) Venture in Western Australia. Daily net production from

the project during 2012 averaged 20,000 barrels of crude oil and condensate,

428 million cubic feet of natural gas, and 4,000 barrels of LPG.

Approximately 70 percent of the natural gas was sold in the form of LNG to

major utilities in Asia, primarily under long-term contracts. The remaining

natural gas was sold to the Western Australia domestic market. The

concession for the NWS Venture expires in 2034.

 The North Rankin 2 project continued to advance during 2012, with

start-up expected in mid-2013. The project is designed to recover remaining

low-pressure natural gas from the North Rankin and Perseus fields to meet

gas supply needs and maintain NWS production capacity of about

2 billion cubic feet of natural gas and 39,000 barrels of condensate. Total

estimated projects costs are $5.4 billion. Proved reserves have been

recognized for the project. The project's estimated economic life exceeds 20

years from the time of start-up.

 In October 2012, the company exchanged its 16.7 percent interest in the

East Browse leases and its 20 percent interest in the West Browse leases for

financial consideration and a 33.3 percent interest in the WA-205-P and

WA-42-R blocks in the Carnarvon Basin and now holds a 100 percent

interest in these blocks, which contain the Clio and Acme fields. The

company retains other nonoperated working interests ranging from 24.8

percent to 50 percent in three other blocks in the Browse Basin. In Block

WA-274-P, drilling in the fourth quarter 2012 resulted in a natural gas

discovery at the Crown prospect.

21
Europe

In Europe, the company is engaged in upstream activities in Bulgaria,

Denmark, Lithuania, the Netherlands, Norway, Poland, Romania,

Ukraine and the United Kingdom. Net oil-equivalent production in Europe

averaged 114,000 barrels per day during 2012.

Denmark: Chevron has a 12 percent working interest in the partneroperated Danish Underground Consortium (DUC), which produces crude

oil and natural gas from 13 fields in the Danish North Sea. Net oilequivalent production in 2012 from DUC averaged 36,000 barrels per day,

composed of 24,000 barrels of crude oil and 74 million cubic feet of natural

gas. In July 2012, as part of a 30-year concession extension, the state-owned

Danish North Sea Fund received a 20 percent ownership of the DUC in

exchange for the previous 20 percent government profit-take arrangements

and the company's interest was reduced from 15 percent to 12 percent. The

concession expires in 2042.

Netherlands: Chevron operates and holds interests ranging from

34.1 percent to 80 percent in 10 blocks in the Dutch sector of the North Sea.

In 2012, the company’s net oil-equivalent production was 9,000 barrels per

day, composed of 2,000 barrels of crude oil and 42 million cubic feet of

natural gas.

Norway: The company holds a 7.6 percent nonoperated working interest in

the Draugen Field. The company’s net production averaged 3,000 barrels of

oil-equivalent per day during 2012. Chevron is the operator and has a

40 percent working interest in exploration licenses PL 527 and PL 598.

Both licenses are in the deepwater portion of the Norwegian Sea.

United Kingdom: The company’s average net oil-equivalent production in

2012 from 10 offshore fields was 66,000 barrels per day, composed of

46,000 barrels of liquids and 122 million cubic feet of natural gas. Most of

the production was from three fields: the 85 percent-owned and operated

Captain Field, the 23.4 percent-owned and operated Alba Field, and the

32.4 percent-owned and jointly operated Britannia Field.

 Procurement and fabrication activities began in 2012 for the Clair Ridge

project, located west of the Shetland Islands, in which the company has a

19.4 percent nonoperated working interest. The project is the second

development phase of the Clair Field. Total planned design capacity is

120,000 barrels of crude oil per day, and the total estimated cost of the

project is $7 billion. Production is scheduled to begin in 2016 and the

project's estimated economic life exceeds 40 years from the time of start-up.

Proved reserves have been recognized for the Clair Ridge project.

 At the 70 percent-owned and operated Alder discovery, FEED activities

progressed during 2012, and a final investment decision is planned for late

2013. The 40 percent-owned and operated Rosebank Project northwest of the

Shetland Islands entered FEED in July 2012. A final investment decision is

planned for 2014. Maximum total daily production is expected to reach

64,000 barrels of liquids and 42 million cubic feet of natural gas. At the end

of 2012, proved reserves had not been recognized for these projects.

 An unsuccessful exploration well was drilled at the Aberlour prospect

west of the Shetland Islands. Full and partial block relinquishments were

made during 2012 under Licenses P119 (Strathspey area), P1026, P1191

and P1194 (Aberlour).

22
Bulgaria: In June 2011, the Bulgarian government advised that Chevron

had submitted a winning tender for a permit for exploration in a 1.1 millionacre area in northeast Bulgaria. In January 2012, prior to execution of the

license agreement, the Bulgarian government announced the withdrawal of

the decision awarding the permit and the Bulgarian parliament imposed a

ban on hydraulic fracturing, a technology commonly used for shale

development and production. Chevron continues to work with the

government of Bulgaria to provide the necessary assurances to both the

government and the public that hydrocarbons from shale can be developed

safely and responsibly.

Lithuania: In October 2012, Chevron acquired a 50 percent interest in a

Lithuanian exploration and production company. In 2013, the affiliate plans

to commence shale exploration activities in the 394,000-acre Rietavas block.

Poland: Chevron holds four shale concessions in southeast Poland

(Frampol, Grabowiec, Krasnik and Zwierzyniec). All four exploration

licenses are 100 percent-owned and operated and comprise a total of

1.1 million acres. During 2012, drilling was completed on the first well in

the Grabowiec concession and evaluation of this well continued into early

2013. An initial well was also drilled in the Frampol concession in 2012.

Drilling of a well in the Zwierzyniec concession commenced in

December 2012, and continued exploratory drilling of the concessions is

planned for 2013.

Romania: The company holds a 100 percent interest and operates the

Barlad shale concession. This license is located in northeast Romania and

covers 1.6 million acres. Drilling of an exploration well is planned for

second-half 2013. In March 2012, three additional petroleum concession

agreements, covering approximately 670,000 acres in southeast Romania,

were approved by the government of Romania. Chevron holds a 100 percent

interest and operates the concessions. Acquisition of 2-D seismic data

across these concessions is expected to commence in second-half 2013.

Ukraine: In 2012, Chevron was the successful bidder for the right to

exclusively negotiate a 50-year PSC with the government of Ukraine for the

Oleska block in western Ukraine. Chevron is expected to operate and hold a

50 percent interest in the 1.6 million-acre concession. As of early 2013, the

PSC and Joint Operating Agreement terms were being negotiated.

Sales of Natural Gas and Natural Gas Liquids

The company sells natural gas and natural gas liquids from its producing

operations under a variety of contractual arrangements. In addition, the

company also makes third-party purchases and sales of natural gas and

natural gas liquids in connection with its trading activities.

 During 2012, U.S. and international sales of natural gas were

5.5 billion and 4.3 billion cubic feet per day, respectively, which includes

the company’s share of equity affiliates’ sales. Outside the United States,

substantially all of the natural gas sales from the company’s producing

interests are from operations in Australia, Bangladesh, Europe,

Kazakhstan, Indonesia, Latin America, Myanmar, Nigeria, the Philippines

and Thailand.

 U.S. and international sales of natural gas liquids were 157 thousand

and 88 thousand barrels per day, respectively, in 2012. Substantially all of

the international sales of natural gas liquids from the company's producing

interests are from operations in Africa, Kazakhstan, Indonesia and the

United Kingdom.

 Refer to “Selected Operating Data,” on page FS-10 in Management’s

Discussion and Analysis of Financial Condition and Results of Operations,

for further information on the company’s sales volumes of natural gas and

natural gas liquids. Refer also to “Delivery Commitments” on page 7 for

information related to the company’s delivery commitments for the sale of

crude oil and natural gas.

23
Downstream

Refining Operations

At the end of 2012, the company had a refining network capable of

processing about 2.0 million barrels of crude oil per day. Operable capacity

at December 31, 2012, and daily refinery inputs for 2010 through 2012 for

the company and affiliate refineries are summarized in the table below.

 Average crude oil distillation capacity utilization during 2012 was

88 percent, compared with 89 percent in 2011. At the U.S. refineries, crude

oil distillation capacity utilization averaged 87 percent in 2012, compared

with 89 percent in 2011. Chevron processes both imported and domestic

crude oil in its U.S. refining operations. Imported crude oil accounted for

about 77 percent and 85 percent of Chevron’s U.S. refinery inputs in 2012

and 2011, respectively.

 At the Pascagoula Refinery, construction progressed on a facility to

produce approximately 25,000 barrels per day of premium base oil for use

in manufacturing high-performance finished lubricants, such as motor oils

for consumer and commercial applications. Mechanical completion is

expected by year-end 2013. In July 2012, the company completed the sale of

its idled 80,000-barrel-per-day Perth Amboy, New

Jersey, refinery, which was operating as a terminal.

 At the refinery in El Segundo, a new processing unit designed to further

improve the facility’s overall reliability, enhance high-value product yield

and provide additional flexibility to process a broad range of crude slates

came online in July 2012. Similar projects were progressed in 2012 at the

Salt Lake City and Pascagoula refineries and are scheduled to be completed

in late 2013.

 Outside the United States, GS Caltex, a 50 percent-owned equity

affiliate, reached mechanical completion of a 53,000-barrel-per-day gas oil

fluid catalytic cracking unit at the Yeosu Refinery in South Korea in early

2013. The unit is designed to increase high-value product yield and lower

feedstock costs. In 2012, construction was completed on modifications to

the 64 percent-owned Star Petroleum Refinery in Thailand to meet regional

specifications for cleaner fuels. Also in 2012, Caltex Australia Ltd., a

50 percent-owned equity affiliate, announced plans to convert the Kurnell,

Australia, refinery to an import terminal in 2014.

Petroleum Refineries: Locations, Capacities and Inputs

(Crude-unit capacities and crude oil inputs in thousands of barrels per day; includes equity share in affiliates)

December 31, 2012 Refinery Inputs

Locations Number

Operable

Capacity 2012 2011 2010

Pascagoula Mississippi 1 330 335 327 325

El Segundo California 1 269 265 244 250

Richmond California 1 257 142 192 228

Kapolei Hawaii 1 54 46 47 46

Salt Lake City Utah 1 45 45 44 41

Total Consolidated Companies — United States 5 955 833 854 890

Pembroke1 United Kingdom — — — 122 211

Map Ta Phut2 Thailand 1 158 95 — —

Cape Town3 South Africa 1 110 79 77 70

Burnaby, B.C. Canada 1 55 49 43 40

Total Consolidated Companies — International 3 323 223 242 321

Affiliates2,4 Various Locations 6 675 646 691 683

Total Including Affiliates — International 9 998 869 933 1,004

Total Including Affiliates — Worldwide 14 1,953 1,702 1,787 1,894

1 Pembroke was sold in August 2011.

2 As of June 2012, Star Petroleum Refining Company crude input volumes are reported on a consolidated basis. Prior to June 2012, crude volumes reflect a 64 percent equity

interest and are reported in equity affiliates.

3 Chevron holds 100 percent of the common stock issued by Chevron South Africa (Pty) Limited, which owns the Cape Town Refinery. A consortium of South African partners owns

preferred shares ultimately convertible to a 25 percent equity interest in Chevron South Africa (Pty) Limited. None of the preferred shares had been converted as of February 2013.

4 Includes 1,000 and 2,000 barrels per day of refinery inputs in 2011 and 2010, respectively, for interests in refineries that were sold during those periods.

24
Marketing Operations

The company markets petroleum products under the principal brands of

“Chevron,” “Texaco” and “Caltex” throughout many parts of the world.

The following table identifies the company’s and affiliates’ refined products

sales volumes, excluding intercompany sales, for the three years ended

December 31, 2012.

Refined Products Sales Volumes

(Thousands of Barrels per Day)

2012 2011 2010

United States

 Gasoline 624 649 700

 Jet Fuel 212 209 223

 Gas Oil and Kerosene 213 213 232

 Residual Fuel Oil 68 87 9 9

 Other Petroleum Products 1 94 9 9 9 5

 Total United States 1,211 1,257 1,349

International2

 Gasoline 412 447 521

 Jet Fuel 243 269 271

 Gas Oil and Kerosene 496 543 583

 Residual Fuel Oil 210 233 197

 Other Petroleum Products 1 193 200 192

 Total International 1,554 1,692 1,764

Total Worldwide2 2,765 2,949 3,113

1

 Principally naphtha, lubricants, asphalt and coke.

2

 Includes share of equity affiliates’ sales: 522 556 562

 In the United States, the company markets under the Chevron and

Texaco brands. At year-end 2012, the company supplied directly or through

retailers and marketers approximately 8,060 Chevron- and Texaco-branded

motor vehicle service stations, primarily in the southern and western states.

Approximately 470 of these outlets are company-owned or -leased stations.

 Outside the United States, Chevron supplied directly or through retailers

and marketers approximately 8,700 branded service stations, including

affiliates. In British Columbia, Canada, the company markets under the

Chevron brand. The company markets in Latin America using the Texaco

brand. In the Asia-Pacific region, southern Africa, Egypt and Pakistan, the

company uses the Caltex brand. The company also operates through

affiliates under various brand names. In South Korea, the company

operates through its 50 percent-owned equity affiliate, GS Caltex, and in

Australia through its 50 percent-owned equity affiliate, Caltex Australia

Limited.

 The company continued its ongoing effort to concentrate downstream

resources and capital on strategic assets. In 2012, Chevron completed the

sale of the company's fuels marketing, finished lubricants and aviation

fuels businesses in Spain as well as certain fuels marketing and aviation

businesses in eight

countries in the Caribbean. The company's GS Caltex affiliate also

completed the sale of certain power and other assets in South Korea. In

addition, the company converted more than 240 company-operated service

stations into retailer-owned sites in various countries outside the United

States.

 Chevron markets commercial aviation fuel at approximately 120 airports

worldwide. The company also markets an extensive line of lubricant and

coolant products under the brand names Havoline, Delo, Ursa, Meropa and

Taro in the United States and worldwide under the three master brands:

Chevron, Texaco and Caltex.

Chemicals Operations

Chevron owns a 50 percent interest in its Chevron Phillips Chemical

Company LLC (CPChem) equity affiliate. At the end of 2012, CPChem

owned or had joint-venture interests in 36 manufacturing facilities and two

research development centers around the world.

 CPChem’s 35 percent-owned equity affiliate, Saudi Polymers Company,

announced commercial production at its new olefins and derivatives facility

in Al-Jubail, Saudi Arabia, in October 2012. In the United States, CPChem

commenced construction of a 1-hexene plant at the company’s Cedar Bayou

complex in Baytown, Texas, with a design capacity of 250,000 metric tons

per year. Start-up is expected in 2014. In 2012, CPChem also commenced

front-end engineering and design for several projects on the U.S. Gulf

Coast, which are expected to capitalize on advantaged feedstock sourced

from emerging shale gas development in North America. These include an

ethane cracker with an annual design capacity of 1.5 million metric tons of

ethylene to be located at the Cedar Bayou complex in Baytown, Texas, and

two polyethylene facilities to be located in Old Ocean, Texas, each with an

annual design capacity of 500,000 metric tons.

 Chevron’s Oronite brand lubricant and fuel additives business is a

leading developer, manufacturer and marketer of performance additives for

lubricating oils and fuels. The company owns and operates facilities in

Brazil, France, Japan, the Netherlands, Singapore and the United States

and has equity interests in facilities in India and Mexico. Oronite lubricant

additives are blended into refined base oil to produce finished lubricant

packages used primarily in engine applications such as passenger car,

heavy-duty diesel, marine, locomotive and motorcycle engines, and

additives for fuels that are blended to improve engine performance and

extend engine life. In 2012, the company began construction on a project to

expand the capacity of the existing additives plant in Singapore. The project

is expected to double the plant's capacity since it was commissioned in

1999 and to begin commercial operations in 2014.

25
Transportation

Pipelines: Chevron owns and operates an extensive network of crude oil,

refined product, chemical, natural gas liquid and natural gas pipelines and

other infrastructure assets in the United States. The company also has

direct and indirect interests in other U.S. and international pipelines. The

company’s ownership interests in pipelines are summarized in the following

table.

Pipeline Mileage at December 31, 2012

Net Mileage1,2

United States:

 Crude Oil 1,969

 Natural Gas 2,396

 Petroleum Products 6,009

Total United States 10,374

International:

 Crude Oil 696

 Natural Gas 199

 Petroleum Products 334

Total International 1,229

Worldwide 11,603

1 Includes company’s share of pipeline mileage owned by equity affiliates.

2 Excludes gathering pipelines relating to the crude oil and natural gas production

function.

 The company continues to lead the construction of a 136-mile, 24-inch

crude oil pipeline from the planned Jack/St. Malo facility to a platform in

Green Canyon Block 19 on the U.S. Gulf of Mexico shelf, where there is

an interconnect to pipelines delivering crude oil into Texas and Louisiana.

The project is expected to be completed by start-up of the production facility

in 2014.

 In December 2012, the company executed agreements to sell the 100

percent-owned and operated Northwest Products System. This system

consisted of a 760-mile refined products pipeline running from Salt Lake

City, Utah, to Spokane, Washington, a dedicated jet fuel pipeline serving

the Salt Lake City International Airport, and three refined products

terminals located in Idaho and Washington. The sale is pending regulatory

approval and is expected to be completed in first-half 2013. In addition, the

company is in the process of relinquishing its interest in the Trans Alaska

Pipeline System.

 Refer to pages 14, 15, 16 and 17 in the Upstream section for

information on the Chad/Cameroon pipeline, the West African Gas Pipeline,

the Baku-Tbilisi-Ceyhan Pipeline, the Western Route Export Pipeline and

the Caspian Pipeline Consortium.

Tankers: All tankers in Chevron’s controlled seagoing fleet were utilized

during 2012. During 2012, the company had 51 deep-sea vessels chartered

on a voyage basis, or for a period of less than one year. The following table

summarizes the capacity of the company’s controlled fleet.

Controlled Tankers at December 31, 20121

U.S. Flag Foreign Flag

Cargo

Capacity

Cargo

Capacity

Number

(Millions of

Barrels) Number

(Millions of

Barrels)

Owned — — 1 1.1

Bareboat-Chartered 4 1.4 18 27.2

Time-Chartered2 3 1.0 11 8.9

 Total 7 2.4 30 37.2

1 Consolidated companies only. Excludes tankers chartered on a voyage basis, those

with dead-weight tonnage less than 25,000 and those used exclusively for storage.

2 Tankers chartered for more than one year.

 The company’s U.S.-flagged fleet is engaged primarily in transporting

refined products in the coastal waters of the United States.

 The foreign-flagged vessels are engaged primarily in transporting crude

oil from the Middle East, Southeast Asia, the Black Sea, South America,

Mexico and West Africa to ports in the United States, Europe, Australia and

Asia. The company’s foreign-flagged vessels also transport refined products

and feedstocks to and from various locations worldwide.

 In 2012, the company ordered eight new vessels, a combination of

bareboat charters and new builds contracts, to modernize the fleet and

increase LNG coverage. In addition to the vessels ordered in 2012, the

company has prior contracts in place to build LNG carriers and a dynamicpositioning shuttle tanker to support future upstream projects. The

company also owns a one-sixth interest in each of seven LNG carriers

transporting cargoes for the North West Shelf Venture in Australia.

Other Businesses

Mining: Chevron’s U.S.-based mining company concluded the divestment

of its remaining coal mining operations. In 2012, the company completed

the sale of its Kemmerer, Wyoming, surface coal mine and the sale of its

50 percent interest in Youngs Creek Mining Company, LLC, which was

formed to develop a coal mine in northern Wyoming. Activities related to

final reclamation continued in 2012 at the company-operated surface coal

mine in McKinley, New Mexico.

26
 Chevron also owns and operates the Questa molybdenum mine in New

Mexico. At year-end 2012, Chevron had 160 million pounds of proven

molybdenum reserves at Questa. Production and underground development

at Questa continued at reduced levels in 2012 in response to weak prices for

molybdenum.

Power Generation: Chevron’s Global Power Company manages interests

in 11 power assets with a total operating capacity of more than 2,200

megawatts, primarily through joint ventures in the United States and Asia.

Ten of these are efficient combined-cycle and gas-fired cogeneration facilities

that utilize recovered waste heat to produce electricity and support industrial

thermal hosts. The 11th facility is a wind farm, located in Casper,

Wyoming, that is designed to optimize the use of a decommissioned refinery

site for delivery of clean, renewable energy to the local utility.

 Chevron also has major geothermal operations in Indonesia and the

Philippines and is evaluating several advanced solar technologies for use in

oil field operations as part of its renewable energy strategy. For additional

information on the company’s geothermal operations and renewable energy

projects, refer to page 19 in the Upstream section and “Research and

Technology” below.

Chevron Energy Solutions (CES): CES is a wholly owned subsidiary

that develops and builds sustainable energy projects that increase energy

efficiency and production of renewable power, reduce energy costs, and

ensure reliable, high-quality energy for government, education and business

facilities. CES has developed hundreds of projects that have helped

customers reduce their energy costs and environmental impact. In 2012,

CES completed several public sector programs, including a first-of-its-kind

microgrid at the Santa Rita jail in Alameda County, and renewable and

efficiency programs for Huntington Beach City School District, South San

Francisco Unified School District and Union City, all in California, plus

Rootstown Local School District in Ohio. CES also completed an energy

efficiency program at the Detroit Arsenal and a combined renewable power

production and heating project at the Marine Corps Logistics Base in

Albany, Georgia. CES is also guiding the work of the new Chevron Center

for Sustainable Energy Efficiency in Qatar. In December 2012, CES and

its partners inaugurated the first large scale solar testing in Qatar. The

evaluation will help determine the most appropriate solar technologies for the

Middle East.

Research and Technology: The company’s energy technology

organization supports Chevron’s upstream and downstream businesses by

providing technology, services and competency development in earth

sciences; reservoir and production engineering; drilling and completions;

facilities engineering; manufacturing; process technology; catalysis;

technical computing; and health, environment and safety disciplines. The

information technology organization integrates computing,

telecommunications, data management, security and network technology to

provide a standardized digital infrastructure and enable Chevron’s global

operations and business processes.

 Chevron's venture capital investment group manages investments and

projects in emerging energy technologies and their integration into Chevron’s

core businesses. As of the end of 2012, the venture capital group continued

to explore technologies such as next-generation biofuels, advanced solar and

enhanced pipeline inspection methods. In 2012, the company continued

evaluation of a solar-to-steam generation project in use to support enhancedoil-recovery operations in Coalinga, California. This project was

commissioned to test the viability of using solar power to produce steam to

improve oil recovery.

 In 2012, the company launched a new tank technology for storing water

at hydraulic fracturing operations. These patent-pending modular metal

tanks can be quickly assembled and taken apart for reuse at other wells.

This enables drilling and fracturing without the need for water storage pits

and is intended to result in enhanced safety, less land disturbance, smaller

drill site pads and significantly lower costs. The first fully operational tank

was brought into service in Ohio.

 Chevron’s research and development expenses were $648 million,

$627 million and $526 million for the years 2012, 2011 and 2010,

respectively.

 Some of the investments the company makes in the areas described

above are in new or unproven technologies and business processes, and

ultimate technical or commercial successes are not certain.

Environmental Protection: The company designs, operates and

maintains its facilities to avoid potential spills or leaks and minimize the

impact of those that may occur. Chevron requires its facilities and

operations to have operating standards and processes and emergency

response plans that address all credible and significant risks identified by

site-specific risk and impact assessments. Chevron also requires that

sufficient resources be available to execute these plans. In the unlikely event

that a major spill or leak occurs, Chevron also maintains a Worldwide

Emergency Response Team comprised of employees who are trained in

various aspects of emergency response, including post-incident remediation.

 To complement the company’s capabilities, Chevron maintains active

membership in international oil spill response cooperatives, including the

Marine Spill Response Corporation, which operates in U.S. territorial

waters, and Oil Spill Response, Ltd. (OSRL), which operates globally. The

company is a founding member of the Marine Well Containment Company,

whose primary mission is to expediently deploy containment equipment and

systems to capture and contain crude oil in the unlikely event of a future

loss of control of a deepwater well in the Gulf of Mexico.

27
In addition, the company is a member of the Subsea Well Response Project

(SWRP). SWRP’s objective is to further develop the industry’s capability to

contain and shut in subsea well control incidents in different regions of the

world.

 Refer to Management's Discussion and Analysis of Financial Condition

and Results of Operations on pages FS-15 and FS-16 for additional

information on environmental matters and their impact on Chevron and on

the company's 2012 environmental expenditures. Refer to page FS-15 and

Note 24 on page FS-58 for a discussion of environmental remediation

provisions and year-end reserves. Refer also to Item 1A. Risk Factors on

pages 28 through 30 for a discussion of greenhouse gas regulation and

climate change.

Web Site Access to SEC Reports

The company’s Internet Web site is www.chevron.com. Information

contained on the company’s Internet Web site is not part of this Annual

Report on Form 10-K. The company’s Annual Reports on Form 10-K,

Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any

amendments to these reports filed or furnished pursuant to Section 13(a) or

15(d) of the Securities Exchange Act of 1934 are available free of charge on

the company’s Web site soon after such reports are filed with or furnished

to the Securities and Exchange Commission (SEC). The reports are also

available on the SEC’s Web site at www.sec.gov.

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 pay

dividends and fund capital and exploratory expenditures. Nevertheless,

some inherent risks could materially impact the company’s financial results

of operations or financial condition.

Chevron is exposed to the effects of changing commodity prices:

Chevron is primarily in a commodities business that has a history of price

volatility. The single largest variable that affects the company’s results of

operations is the price of crude oil, which can be influenced by general

economic conditions, industry inventory levels, production quotas imposed

by the Organization of Petroleum Exporting Countries (OPEC), weatherrelated damage and disruptions, competing fuel prices, and geopolitical

risk. Chevron accepts the risk of changing commodity prices as part of its

business planning process. As such, an investment in the company carries

significant exposure to fluctuations in global crude oil prices.

 During extended periods of historically low prices for crude oil, the

company’s upstream earnings and capital and exploratory expenditure

programs will be negatively affected. Upstream assets may also become

impaired. The impact on downstream earnings is dependent upon the

supply and demand for refined products and the associated margins on

refined product sales.

The scope of Chevron’s business will decline if the company does not

successfully develop resources: The company is in an extractive

business; therefore, if Chevron is not successful in replacing the crude oil

and natural gas it produces with good prospects for future production or

through acquisitions, the company’s business will decline. Creating and

maintaining an inventory of projects depends on many factors, including

obtaining and renewing rights to explore, develop and produce

hydrocarbons; drilling success; ability to bring long-lead-time, capitalintensive projects to completion on budget and on schedule; and efficient

and profitable operation of mature properties.

The company’s operations could be disrupted by natural or human

factors: Chevron operates in both urban areas and remote and sometimes

inhospitable regions. The company’s operations and facilities are therefore

subject to disruption from either natural or human causes beyond its

control, including hurricanes, floods and other forms of severe weather,

war, civil unrest and other political events, fires, earthquakes, system

failures, cyber threats and terrorist acts, any of which could result in

suspension of operations or harm to people or the natural environment.

The company’s operations have inherent risks and hazards that

require significant and continuous oversight: Chevron’s results depend

on its ability to identify and mitigate the risks and hazards inherent to

operating in the crude oil and natural gas industry. The company seeks to

minimize these operational risks by carefully designing and building its

facilities and conducting its operations in a safe and reliable manner.

However, failure to manage these risks effectively could result in unexpected

incidents, including releases, explosions or mechanical failures resulting in

personal injury, loss of life, environmental damage, loss of revenues, legal

liability and/or disruption to operations. Chevron has implemented and

maintains a system of corporate policies, behaviors and compliance

mechanisms to manage safety, health, environmental, reliability and

efficiency risks; to verify compliance with applicable laws and policies;

and to respond to and learn from unexpected incidents. Nonetheless, in

certain situations where Chevron is not the operator, the company may have

limited influence and control over third parties, which may limit its ability

to manage and control such risks.

Chevron’s business subjects the company to liability risks from

litigation or government action: The company produces, transports,

refines and markets materials with potential toxicity, and it purchases,

handles and disposes of other potentially toxic materials in the course of its

business. Chevron's operations also produce byproducts, which may be

considered pollutants. Often these operations are conducted through joint

ventures over which the company may have limited influence and control.

Any of these activities could result in liability or significant delays in

operations arising from private litigation or government

28
action, either as a result of an accidental, unlawful discharge or as a result

of new conclusions about the effects of the company’s operations on human

health or the environment. In addition, to the extent that societal pressures or

political or other factors are involved, it is possible that such liability could

be imposed without regard to the company’s causation of or contribution to

the asserted damage, or to other mitigating factors.

 For information concerning some of the litigation in which the company

is involved, including information relating to Ecuador matters, see Note 13

to the Consolidated Financial Statements, beginning on FS-40.

The company does not insure against all potential losses, which could

result in significant financial exposure: The company does not have

commercial insurance or third-party indemnities to fully cover all

operational risks or potential liability in the event of a significant incident or

series of incidents causing catastrophic loss. As a result, the company is, to

a substantial extent, self-insured for such events. The company relies on

existing liquidity, financial resources and borrowing capacity to meet shortterm obligations that would arise from such an event or series of events. The

occurrence of a significant incident or unforeseen liability for which the

company is not fully insured or for which insurance recovery is

significantly delayed could have a material adverse effect on the company’s

results of operations or financial condition.

Political instability and significant changes in the regulatory

environment could harm Chevron’s business: The company’s

operations, particularly exploration and production, can be affected by

changing economic, regulatory and political environments in the various

countries in which it operates. As has occurred in the past, actions could be

taken by governments to increase public ownership of the company’s

partially or wholly owned businesses or to impose additional taxes or

royalties.

 In certain locations, governments have imposed or proposed restrictions

on the company’s operations, export and exchange controls, burdensome

taxes, and public disclosure requirements that might harm the company’s

competitiveness or relations with other governments or third parties. In other

countries, political conditions have existed that may threaten the safety of

employees and the company’s continued presence in those countries, and

internal unrest, acts of violence or strained relations between a government

and the company or other governments may adversely affect the company’s

operations. Those developments have, at times, significantly affected the

company’s related operations and results and are carefully considered by

management when evaluating the level of current and future activity in such

countries. At December 31, 2012, 21 percent of the company’s net proved

reserves were located in Kazakhstan. The company also has significant

interests in OPEC-member countries, including Angola, Nigeria and

Venezuela and in the Partitioned Zone between Saudi Arabia

and Kuwait. Twenty-one percent of the company’s net proved reserves,

including affiliates, were located in OPEC countries at December 31, 2012.

Regulation of greenhouse gas emissions could increase Chevron’s

operational costs and reduce demand for Chevron’s products:

Continued political attention to issues concerning climate change, the role of

human activity in it, and potential mitigation through regulation could have

a material impact on the company’s operations and financial results.

 International agreements and national or regional legislation and

regulatory measures to limit greenhouse emissions are currently in various

stages of discussion or implementation. These and other greenhouse gas

emissions-related laws, policies and regulations may result in substantial

capital, compliance, operating and maintenance costs. The level of

expenditure required to comply with these laws and regulations is uncertain

and is expected to vary depending on the laws enacted in each jurisdiction,

the company’s activities in it and market conditions. Greenhouse gas

emissions that could be regulated include those arising from the company’s

exploration and production of crude oil and natural gas; the upgrading of

production from oil sands into synthetic oil; power generation; the

conversion of crude oil and natural gas into refined products; the

processing, liquefaction and regasification of natural gas; the transportation

of crude oil, natural gas and related products and consumers’ or customers’

use of the company’s products. Some of these activities, such as

consumers’ and customers’ use of the company’s products, as well as

actions taken by the company’s competitors in response to such laws and

regulations, are beyond the company’s control.

 The effect of regulation on the company’s financial performance will

depend on a number of factors including, among others, the sectors

covered, the greenhouse gas emissions reductions required by law, the extent

to which Chevron would be entitled to receive emission allowance

allocations or would need to purchase compliance instruments on the open

market or through auctions, the price and availability of emission

allowances and credits, and the impact of legislation or other regulation on

the company’s ability to recover the costs incurred through the pricing of the

company’s products. Material price increases or incentives to conserve or

use alternative energy sources could reduce demand for products the

company currently sells and adversely affect the company’s sales volumes,

revenues and margins.

Changes in management’s estimates and assumptions may have a

material impact on the company’s consolidated financial statements

and financial or operational performance in any given period: In

preparing the company’s periodic reports under the Securities Exchange Act

of 1934, including its financial statements, Chevron’s management is

required under

29
applicable rules and regulations to make estimates and assumptions as of a

specified date. These estimates and assumptions are based on

management’s best estimates and experience as of that date and are subject

to substantial risk and uncertainty. Materially different results may occur

as circumstances change and additional information becomes known. Areas

requiring significant estimates and assumptions by management include

measurement of benefit obligations for pension and other postretirement

benefit plans; estimates of crude oil and natural gas recoverable reserves;

accruals for estimated liabilities, including litigation reserves; and

impairments to property, plant and equipment. Changes in estimates or

assumptions or the information underlying the assumptions, such as

changes in the company’s business plans, general market conditions or

changes in commodity prices, could affect reported amounts of assets,

liabilities or expenses.

Item1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and character of the company’s crude oil, natural gas and

mining properties and its refining, marketing, transportation and chemicals

facilities are described on page 3 under Item 1. Business. Information

required by Subpart 1200 of Regulation S-K (“Disclosure by Registrants

Engaged in Oil and Gas Producing Activities”) is also contained in Item 1

and in Tables I through VII on pages FS-62 through FS-75. Note 12,

“Properties, Plant and Equipment,” to the company’s financial statements

is on page FS-40.

Item 3. Legal Proceedings

Ecuador: Information related to Ecuador matters is included in Note 13 to

the Consolidated Financial Statements under the heading Ecuador,

beginning on page FS-40.

Certain Governmental Proceedings:

 In 2011, the California Air Resources Board (CARB) made penalty

demands with respect to four notices of violation against Chevron for

alleged violations of CARB's fuel blend regulations at certain California

terminals and refineries. In November 2011, the statute of limitations

expired with respect to two of the notices of violation. On January 28, 2013,

settlements were executed, which resolved the remaining two notices of

violation. One settlement, with respect to the Richmond Refinery, resulted in

the payment of a civil penalty in the amount of $192,500, and the other

settlement, relating to

the San Jose and Sacramento terminals, resulted in the payment of a civil

penalty in the amount of $205,000. 

 In July 2009, the Hawaii Department of Health (DOH) alleged that

Chevron is obligated to pay stipulated civil penalties exceeding $100,000 in

conjunction with commitments Chevron undertook to install and operate

certain air emission control equipment at its Hawaii Refinery pursuant to a

Clean Air Act settlement with the United States Environmental Protection

Agency (EPA) and the DOH. Chevron has disputed many of the

allegations. 

The EPA indicated that it would assess Chevron's Salt Lake City Refinery

a civil penalty for alleged violations of federal requirements and Utah's air

quality laws. These alleged violations were the subject of an August 20,

2008, EPA Notice of Violation (NOV) for which no penalty was assessed at

the time. It appears that the resolution of this NOV may result in the

payment of a civil penalty exceeding $100,000.

 The South Coast Air Quality Management District (SCAQMD) issued

an NOV to Chevron's Huntington Beach, California, terminal seeking a

civil penalty for alleged violations involving the repair of two holes in the

roof of a tank at the terminal. On January 24, 2013, Chevron U.S.A. Inc.

executed a settlement agreement with the SCAQMD and made payment of

$100,000 to resolve the NOV issued to the Huntington Beach terminal.

 In September and November 2012, Chevron's Richmond Refinery

received from the Bay Area Air Quality Management District (BAAQMD)

proposals to resolve 47 alleged NOVs related to air quality regulations. A

single settlement agreement has been finalized covering 28 of those NOVs

for payment of $145,600 in civil penalties. Resolution of the remaining

NOVs is pending and may result in a civil penalty exceeding $100,000.

 In April 2012, the South Coast Air Quality Management District

(SCAQMD) issued a letter seeking to settle five separate and unrelated

NOVs issued to Chevron's El Segundo Refinery in 2011 for alleged

violations of various state and local rules relating to air emissions. On

January 24, 2013, Chevron U.S.A. Inc. executed a settlement agreement

with SCAQMD and made payment of $300,000 to resolve the five NOVs

issued to the El Segundo Refinery.

Item 4. Mine Safety Disclosures

Information concerning mine safety violations or other regulatory matters

required by Section 1503(a) of the Dodd-Frank Wall Street Reform and

Consumer Protection Act and Item 104 of Regulation S-K (17 C.F.R.

§ 229.104) is included in Exhibit 95 of this Annual Report on Form 10-K.

30
PART II

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The information on Chevron’s common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of

record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-20.

Chevron Corporation Issuer Purchases of Equity Securities

Maximum

Total Number of Number of Shares

Total Number Average Shares Purchased as that May Yet be

of Shares Price Paid Part of Publicly Purchased Under

Period Purchased(1)(2) per Share Announced Program the Program(2)

Oct. 1 – Oct. 31, 2012 3,644,071 $114.16 3,644,045 —

Nov. 1 – Nov. 30, 2012 4,290,367 105.23 4,290,000 —

Dec. 1 – Dec. 31, 2012 3,555,702 107.59 3,555,702 —

Total Oct. 1 – Dec. 31, 2012 11,490,140 $108.79 11,489,747 —

_________________________________

(1) Includes common shares repurchased from company employees for required personal income tax withholdings on the exercise of the stock options and shares delivered or

attested to in satisfaction of the exercise price by holders of the employee stock options. The options were issued to and exercised by management under Chevron long-term

incentive plans and Unocal stock option plans.

(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 December 31, 2012, 97,698,628 shares had been acquired under this program for $10 billion.

Item 6. Selected Financial Data

The selected financial data for years 2008 through 2012 are presented on

page FS-61.

Item 7. Management’s Discussion and Analysis of Financial

Condition and Results of Operations

The index to Management’s Discussion and Analysis of Financial

Condition and Results of Operations, Consolidated Financial Statements

and Supplementary Data is presented on page FS-1.

Item 7A. Quantitative and Qualitative Disclosures About Market

Risk

The company’s discussion of interest rate, foreign currency and commodity

price market risk is contained in Management’s Discussion and Analysis

of Financial Condition and Results of Operations — “Financial and

Derivative Instruments,” beginning on page FS-14 and in Note 9 to the

Consolidated Financial Statements, “Financial and Derivative

Instruments,” beginning on page FS-35.

Item 8. Financial Statements and Supplementary Data

The index to Management’s Discussion and Analysis, Consolidated

Financial Statements and Supplementary Data is presented on page FS-1.

31
Item 9. Changes in and Disagreements With Accountants on

Accounting and Financial Disclosure

None.

Item 9A. 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 the Chief Financial Officer, the effectiveness of

the company’s disclosure controls and procedures (as defined in Rule 13a15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the

“Exchange Act”)) as of the end of the period covered by this report. Based

on this evaluation, the Chief Executive Officer and the Chief Financial

Officer concluded that the company’s disclosure controls and procedures

were effective as of December 31, 2012.

(b) Management’s Report on Internal Control Over Financial

Reporting

The company’s management is responsible for establishing and

maintaining adequate internal control over financial reporting, as such term

is defined in Exchange Act Rule 13a-15(f). The

company’s management, including the Chief Executive Officer and the

Chief Financial Officer, conducted an evaluation of the effectiveness of the

company’s internal control over financial reporting based on the Internal

Control — Integrated Framework issued by the Committee of Sponsoring

Organizations of the Treadway Commission. Based on the results of this

evaluation, the company’s management concluded that internal control over

financial reporting was effective as of December 31, 2012.

The effectiveness of the company’s internal control over financial reporting

as of December 31, 2012, has been audited by PricewaterhouseCoopers

LLP, an independent registered public accounting firm, as stated in its

report included on page FS-22.

(c) Changes in Internal Control Over Financial Reporting

During the quarter ended December 31, 2012, 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.

Item 9B. Other Information

None.

32
PART III

Item 10. Directors, Executive Officers and Corporate Governance

Executive Officers of the Registrant at February 22, 2013

The Executive Officers of the Corporation consist of the Chairman of the Board, the Vice Chairman of the Board and such other officers of the Corporation

who are members of the Executive Committee.

Name and Age Current and Prior Positions (up to five years) Current Areas of Responsibility

J.S. Watson 5 6 Chairman of the Board and Chief Executive Officer (since 2010) Chief Executive Officer

Vice Chairman of the Board (2009)

Executive Vice President (2008 to 2009)

Vice President and President of Chevron International Exploration

 and Production Company (2005 through 2007)

G.L. Kirkland 62 Vice Chairman of the Board and Executive Vice President

 (since 2010)

Executive Vice President (2005 through 2009)

Worldwide Exploration and Production

Activities and Global Gas Activities,

including Natural Gas Trading

J.R. Blackwell 54 Executive Vice President (since 2011)

President of Chevron Asia Pacific Exploration and Production

 Company (2008 through 2011)

Managing Director of Chevron Southern Africa Strategic Business

 Unit (2003 to 2007)

Technology; Mining; Project 

Resources Company; 

Procurement

M.K. Wirth 52 Executive Vice President (since 2006)

President of Global Supply and Trading (2004 to 2006)

Worldwide Refining, Marketing,

Lubricants, and Supply and Trading

Activities, excluding Natural Gas Trading;

Chemicals

R.I. Zygocki 5 5 Executive Vice President (since 2011)

Vice President, Policy, Government and Public Affairs

 (2007 through 2011)

Vice President, Health, Environment and Safety (2003 through 2007)

Strategy and Planning; Health,

Environment and Safety; Policy,

Government and Public Affairs

P.E. Yarrington 5 6 Vice President and Chief Financial Officer (since 2009)

Vice President and Treasurer (2007 through 2008)

Vice President, Policy, Government and Public Affairs

 (2002 to 2007)

Finance

R.H. Pate 50 Vice President and General Counsel (since 2009)

Partner and Head of Global Competition Practice of Hunton & Williams LLP, a

major U.S. law firm (2005 to 2009)

Law, Governance and Compliance

 The information about directors required by Item 401 (a), (d), (e) and

(f) of Regulation S-K and contained under the heading “Election of

Directors” in the Notice of the 2013 Annual Meeting and 2013 Proxy

Statement, to be filed pursuant to Rule 14a-6(b) under the Securities

Exchange Act of 1934 (the “Exchange Act”), in connection with the

company’s 2013 Annual Meeting of Stockholders (the “ 2013 Proxy

Statement”), is incorporated by reference into this Annual Report on

Form 10-K.

 The information required by Item 405 of Regulation S-K and contained

under the heading “Stock Ownership Information — Section 16(a)

Beneficial Ownership Reporting Compliance” in the 2013 Proxy Statement

is incorporated by reference into this Annual Report on Form 10-K.

 The information required by Item 406 of Regulation S-K

and contained under the heading “Board Operations — Business Conduct

and Ethics Code” in the 2013 Proxy Statement is incorporated by reference

into this Annual Report on Form 10-K.

 The information required by Item 407(d)(4) and (5) of Regulation S-K

and contained under the heading “Board Operations — Board Committee

Membership and Functions” in the 2013 Proxy Statement is incorporated by

reference into this Annual Report on Form 10-K.

 There were no changes to the process by which stockholders may

recommend nominees to the Board of Directors during the last fiscal year.

33
Item 11. Executive Compensation

The information required by Item 402 of Regulation S-K and contained

under the headings “Executive Compensation” and “Director

Compensation” in the 2013 Proxy Statement is incorporated by reference

into this Annual Report on Form 10-K.

 The information required by Item 407(e)(4) of Regulation S-K and

contained under the heading “Board Operations — Board Committee

Membership and Functions” in the 2013 Proxy Statement is incorporated by

reference into this Annual Report on Form 10-K.

 The information required by Item 407(e)(5) of Regulation S-K and

contained under the heading “Board Operations — Management

Compensation Committee Report” in the 2013 Proxy Statement is

incorporated herein by reference into this Annual Report on Form 10-K.

Pursuant to the rules and regulations of the SEC under the Exchange Act,

the information under such caption incorporated by reference from the 2013

Proxy Statement shall not be deemed to be “soliciting material,” or to be

“filed” with the Commission, or subject to Regulation 14A or 14C or the

liabilities of Section 18 of the Exchange Act nor shall it be deemed

incorporated by reference into any filing under the Securities Act of 1933.

Item 12. Security Ownership of Certain Beneficial Owners and

Management and Related Stockholder Matters

The information required by Item 403 of Regulation S-K and contained

under the heading “Stock Ownership Information — Security Ownership

of Certain Beneficial Owners and Management” in the 2013 Proxy

Statement is incorporated by reference into this Annual Report on Form 10-

K.

 The information required by Item 201(d) of Regulation S-K and

contained under the heading “Equity Compensation Plan Information” in

the 2013 Proxy Statement is incorporated by reference into this Annual

Report on Form 10-K.

Item 13. Certain Relationships and Related Transactions, and

Director Independence

The information required by Item 404 of Regulation S-K and contained

under the heading “Board Operations — Transactions with Related

Persons” in the 2013 Proxy Statement is incorporated by reference into this

Annual Report on Form 10-K.

 The information required by Item 407(a) of Regulation S-K and

contained under the heading “Election of Directors — Independence of

Directors” in the 2013 Proxy Statement is incorporated by reference into this

Annual Report on Form 10-K.

Item 14. Principal Accounting Fees and Services

The information required by Item 9(e) of Schedule 14A and contained

under the heading “Proposal to Ratify the

Appointment of the Independent Registered Public Accounting Firm” in the

2013 Proxy Statement is incorporated by reference into this Annual Report

on Form 10-K.

34
PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) The following documents are filed as part of this report:

(1) Financial Statements:

Page(s)

Report of Independent Registered Public Accounting Firm — PricewaterhouseCoopers LLP FS-22

Consolidated Statement of Income for the three years ended December 31, 2012 FS-23

Consolidated Statement of Comprehensive Income for the three years ended December 31, 2012 FS-24

Consolidated Balance Sheet at December 31, 2012 and 2011 FS-25

Consolidated Statement of Cash Flows for the three years ended December 31, 2012 FS-26

Consolidated Statement of Equity for the three years ended December 31, 2012 FS-27

Notes to the Consolidated Financial Statements FS-28 to FS-60

(2) Financial Statement Schedules:

Included on page 36 is Schedule II - Valuation and Qualifying Accounts.

(3) Exhibits:

The Exhibit Index on pages E-1 through E-2 lists the exhibits that are filed as part of this report.

35
Schedule II — Valuation and Qualifying Accounts

(Millions of Dollars)

Year Ended December 31

2012 2011 2010

Employee Termination Benefits

Balance at January 1 $ 63 $ 145 $ 13

Additions charged to expense 3 — 235

Payments (36) (82) (103)

Balance at December 31 $ 30 $ 63 $ 145

Allowance for Doubtful Accounts

Balance at January 1 $ 167 $ 239 $ 293

Additions (reductions) to expense (4) 4 (13)

Bad debt write-offs (8) (76) (41)

Balance at December 31 $ 155 $ 167 $ 239

Deferred Income Tax Valuation Allowance*

Balance at January 1 $ 11,096 $ 9,185 $ 7,921

Additions to deferred income tax expense 5,471 2,216 1,454

Reduction of deferred income tax expense (1,124) (305) (190)

Balance at December 31 $ 15,443 $ 11,096 $ 9,185

* See also Note 14 to the Consolidated Financial Statements, beginning on page FS-43.

36
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, on the 22nd day of February, 2013.

 Chevron Corporation 

By /s/ JOHN S. WATSON

John S. Watson, Chairman of the Board 

and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and

in the capacities indicated on the 22nd day of February, 2013.

Principal Executive Officers

(and Directors) Directors

/s/JOHN S. WATSON

John S. Watson, Chairman of the 

Board and Chief Executive Officer

LINNET F. DEILY*

Linnet F. Deily

/s/GEORGE L. KIRKLAND

George L. Kirkland, Vice Chairman 

of the Board

ROBERT E. DENHAM*

Robert E. Denham

ALICE P. GAST*

Alice P. Gast

Principal Financial Officer

ENRIQUE HERNANDEZ, JR.*

Enrique Hernandez, Jr.

/s/PATRICIA E. YARRINGTON

Patricia E. Yarrington, Vice President 

and Chief Financial Officer 

CHARLES W. MOORMAN*

Charles W. Moorman 

KEVIN W. SHARER*

Kevin W. Sharer

Principal Accounting Officer

/s/MATTHEW J. FOEHR

Matthew J. Foehr, Vice President 

and Comptroller

JOHN G. STUMPF*

John G. Stumpf

RONALD D. SUGAR*

Ronald D. Sugar

*By: /s/LYDIA I. BEEBE

Lydia I. Beebe, 

Attorney-in-Fact

CARL WARE*

Carl Ware 

37
THIS PAGE INTENTIONALLY LEFT BLANK

38
Financial Table of Contents

FS-2 FS-28

Management’s Discussion and Analysis of 

Financial Condition and Results of Operations Notes to the Consolidated Financial Statements

Key Financial Results FS-2 Note 1 Summary of Significant Accounting Policies FS-28

Earnings by Major Operating Area FS-2 Note 2 Noncontrolling Interests FS-30

Business Environment and Outlook FS-2 Note 3 Information Relating to the Consolidated 

Statement of Cash Flows FS-31

Operating Developments FS-5 Note 4 Summarized Financial Data – Chevron U.S.A. Inc. FS-32

Results of Operations FS-6 Note 5 Summarized Financial Data – 

Chevron Transport Corporation Ltd. FS-32

Consolidated Statement of Income FS-9 Note 6 Summarized Financial Data – Tengizchevroil LLP FS-33

Selected Operating Data FS-10 Note 7 Lease Commitments FS-33

Liquidity and Capital Resources FS-11 Note 8 Fair Value Measurements FS-33

Financial Ratios FS-13 Note 9 Financial and Derivative Instruments FS-35

Guarantees, Off-Balance-Sheet Arrangements and Contractual 

Obligations, and Other Contingencies FS-13 Note 10 Operating Segments and Geographic Data FS-36

Financial and Derivative Instruments FS-14 Note 11 Investments and Advances FS-38

Transactions With Related Parties FS-15 Note 12 Properties, Plant and Equipment FS-40

Litigation and Other Contingencies FS-15 Note 13 Litigation FS-40

Environmental Matters FS-15 Note 14 Taxes FS-43

Critical Accounting Estimates and Assumptions FS-16 Note 15 Short-Term Debt FS-46

New Accounting Standards FS-19 Note 16 Long-Term Debt FS-46

Quarterly Results and Stock Market Data FS-20 Note 17 New Accounting Standards FS-47

Note 18 Accounting for Suspended Exploratory Wells FS-47

Note 19 Stock Options and Other Share-Based Compensation FS-48

FS-21

Note 20 Employee Benefit Plans FS-49

Note 21 Equity FS-55

Note 22 Other Contingencies and Commitments FS-55

Consolidated Financial Statements Note 23 Asset Retirement Obligations FS-58

Report of Management FS-21 Note 24 Other Financial Information FS-58

Report of Independent Registered Public Accounting Firm FS-22 Note 25 Earnings Per Share FS-59

Consolidated Statement of Income FS-23 Note 26 Acquisition of Atlas Energy, Inc. FS-60

Consolidated Statement of Comprehensive Income FS-24

Consolidated Balance Sheet FS-25

Consolidated Statement of Cash Flows FS-26 Five-Year Financial Summary FS-61

Consolidated Statement of Equity FS-27 Supplemental Information on Oil and Gas Producing Activities FS-62

FS-1
Management's Discussion and Analysis of

Financial Condition and Results of Operations

Key Financial Results

Millions of dollars, except per-share amounts 2012 2011 2010

Net Income Attributable to

Chevron Corporation $ 26,179 $ 26,895 $ 19,024

Per Share Amounts:

Net Income Attributable to

Chevron Corporation

– Basic $ 13.42 $ 13.54 $ 9.53

– Diluted $ 13.32 $ 13.44 $ 9.48

Dividends $ 3.51 $ 3.09 $ 2.84

Sales and Other

Operating Revenues $ 230,590 $ 244,371 $ 198,198

Return on:

Capital Employed 18.7% 21.6% 17.4%

Stockholders’ Equity 20.3% 23.8% 19.3%

Earnings by Major Operating Area

Millions of dollars 2012 2011 2010

Upstream

United States $ 5,332 $ 6,512 $ 4,122

International 18,456 18,274 13,555

Total Upstream 23,788 24,786 17,677

Downstream

United States 2,048 1,506 1,339

International 2,251 2,085 1,139

Total Downstream 4,299 3,591 2,478

All Other (1,908) (1,482) (1,131)

Net Income Attributable to

Chevron Corporation1,2 $ 26,179 $ 26,895 $ 19,024

1 Includes foreign currency effects: $ (454) $ 121 $ (423)

2 Also referred to as “earnings” in the discussions that follow.

 Refer to the “Results of Operations” section beginning on page FS-6 for a

discussion of financial results by major operating area for the three years

ended December 31, 2012.

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 biggest factor affecting the results of operations

for the company is the level of the price of crude oil. In the downstream business,

crude oil is the largest cost component of refined products. Seasonality is not a

primary driver of changes in the company’s quarterly

earnings during the year.

 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.

 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. 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. 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.

 The company 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 FS-6 for

discussions of net gains on asset sales during 2012. Asset dispositions and

restructurings may also occur in future periods and could result in significant gains

or losses.

 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.

 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. Any of these factors could

FS-2
also inhibit the company’s production capacity in an affected region. The company

closely monitors developments in the countries in which it operates and holds

investments, and seeks to manage risks in operating its facilities and businesses. 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.

 The company continues to actively manage its schedule of work, contracting,

procurement and supply-chain activities to effectively manage costs. However, price

levels for capital and exploratory costs and operating expenses associated with the

production of crude oil and natural gas can 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-anddemand 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 chart above shows the trend in benchmark prices for Brent crude oil, West

Texas Intermediate (WTI) crude oil and U.S. Henry Hub natural gas. The Brent

price averaged $112 per barrel for the full-year 2012, compared to $111 in 2011. As

of mid-February 2013, the Brent price was about $118 per barrel. The majority of

the company’s equity crude production is priced based on the Brent benchmark. The

WTI price averaged $94 per barrel for the full-year 2012, compared to $95 in 2011.

As of mid-February 2013, the WTI price was about $97 per barrel. WTI traded at

a discount to Brent throughout 2012 due to high inventories in the U.S.

midcontinent market driven by strong growth in domestic production.

 A differential in crude oil prices exists between high-quality (high-gravity, lowsulfur) 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 capacity of refineries that are

able to process this lower quality feedstock into light products (motor gasoline, jet

fuel, aviation gasoline and diesel fuel). During 2012, the differential between U.S.

light and heavy crude oil remained below historical norms as light sweet crude oil

production in the midcontinent region increased and outbound capacity at Cushing

remained constrained. Outside of the U.S., the differential narrowed modestly during

2012 as additional heavy crude oil conversion capacity came on line.

 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 FS-10 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-anddemand conditions in those markets. In the United States, prices at Henry Hub

averaged $2.71 per thousand cubic feet (MCF) during 2012, compared with about

$4.00 during 2011. As of mid-February 2013, the Henry Hub spot price was about

$3.30 per MCF. Fluctuations in the price of natural gas in the United States are

closely associated with customer demand relative to the volumes produced in North

America.

 Outside the United States, price changes for natural gas depend on a wide range

of supply, demand and regulatory circumstances. In some locations, Chevron is

investing in long-term projects to install infrastructure to produce and liquefy natural

gas for transport by tanker to other markets. International natural gas realizations

averaged about $6.00 per MCF during 2012, compared with about $5.40 per MCF

during 2011. (See page FS-10 for the company’s average natural gas realizations for

the U.S. and international regions.)

FS-3
Management's Discussion and Analysis of

Financial Condition and Results of Operations

 The company’s worldwide net oil-equivalent production in 2012 averaged 2.610

million barrels per day. About one-fifth of the company’s net oil-equivalent

production in 2012 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 in 2012 or 2011. At their

December 2012 meeting, members of OPEC supported maintaining the current

production quota of 30 million barrels per day, which has been in effect since

December 2008.

 The company estimates that oil-equivalent production in 2013 will average

approximately 2.650 million barrels per day based on an average Brent price of $112

per barrel for the full-year 2012. This estimate is subject to many factors and

uncertainties, including quotas that may be imposed by OPEC, price effects on

entitlement volumes, changes in fiscal terms or restrictions on the scope of company

operations, delays in project startups or ramp-ups, 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. 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.

 Refer to the “Results of Operations” section on pages FS-6 through FS-7 for

additional discussion of the company’s upstream business.

 Refer to Table V beginning on page FS-67 for a tabulation of the company’s

proved net oil and gas reserves by geographic area, at the beginning of 2010 and each

year-end from 2010 through 2012, and an accompanying discussion of major

changes to proved reserves by geographic area for the three-year period ending

December 31, 2012.

 On November 7, 2011, while drilling a development well in the deepwater Frade

Field about 75 miles offshore Brazil, an unanticipated pressure spike caused oil to

migrate from the well bore through a series of fissures to the sea floor, emitting

approximately 2,400 barrels of oil. The source of the seep was substantially contained

within four days and the well was plugged and abandoned. No evidence of any coastal

or wildlife impacts related to this seep has emerged. On March 14, 2012, the

company identified a small, second seep in a different part of the field. As a

precautionary measure, the company and its partners decided to temporarily suspend

field production and received approval from Brazil’s National Petroleum Agency

(ANP) to do so. Chevron and its partners are cooperating with the Brazilian

authorities. On July 19, 2012, ANP issued its final investigative report on the

November 2011 incident. A Brazilian federal district prosecutor filed two civil lawsuits

seeking $10.7 billion in damages for

each of the two seeps. The company is not aware of any basis for damages to be

awarded in any civil lawsuit. On July 31, 2012, a court presiding over the civil

litigation entered a preliminary injunction barring Chevron from conducting oil

production and transportation activities in Brazil pending completion of the legal

proceedings commenced by the federal district prosecutor and the ongoing

proceedings of ANP and the Brazilian environment and natural resources regulatory

agency. On September 28, 2012, the injunction was modified to clarify that Chevron

may continue its containment and mitigation activities under supervision of ANP. On

appeal, on November 27, 2012, the injunction was revoked in its entirety. The

federal district prosecutor also filed criminal charges against 11 Chevron employees.

Jurisdiction for all three matters was moved from Campos to a court in Rio de

Janeiro. On February 19, 2013, the court dismissed the criminal matter, which is

subject to appeal by the prosecutor. Chevron has submitted to ANP a plan for

restarting limited

FS-4
production in the Frade Field. The company’s ultimate exposure related to the

incident is not currently determinable, but could be significant to net income in any

one period.

The company entered into a nonbinding financing term sheet with Petroboscan, a

joint stock company owned 39.2 percent by Chevron, which operates the Boscan

Field in Venezuela. When finalized, the financing is expected to occur in stages over a

limited drawdown period and is intended to support a specific work program to

maintain and increase production to an agreed-upon level. The terms are designed to

support cash needs for ongoing operations and new development, as well as

distributions to shareholders — including current outstanding obligations. The loan

will be repaid from future Petroboscan crude sales. Definitive documents are under

negotiation.

 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, costs

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 its 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. The company

completed a multiyear plan in 2012 to streamline the downstream asset portfolio to

concentrate resources and capital on strategic assets. In third quarter 2012, the

company completed the sale of its Perth Amboy, New Jersey, refinery, which had

been operated as a products terminal in recent years. In 2012, the company

completed the sale of its fuels marketing and aviation businesses in eight countries in

the Caribbean. 

 Refer to the “Results of Operations” section on pages FS-7 through FS-8 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, alternative

fuels, and technology companies.

Operating Developments

Key operating developments and other events during 2012 and early 2013 included

the following:

Upstream

Australia In October 2012, the company acquired additional interests in the Clio and

Acme fields in the Carnarvon Basin in exchange for Chevron's interests in the

Browse development. Consolidating interests in the Carnarvon Basin fits strategically

with long-term plans to grow the Wheatstone area resource base and creates

expansion opportunities for the Wheatstone Project.

In September 2012, the company completed the sale of an equity interest in the

Wheatstone Project to Tokyo Electric.

During 2012 and early 2013, the company announced natural gas discoveries at the

47.3 percent-owned and operated Pontus prospect in Block WA-37-L, the 50

percent-owned and operated Satyr prospect in Block WA-374-P, the 50 percentowned and operated Pinhoe prospect in Block WA-383-P, the 50 percent-owned and

operated Arnhem prospect in Block WA-364-P, and the 50 percent-owned and

operated Kentish Knock South prospect in Block WA-365-P. These discoveries are

expected to contribute to potential expansion opportunities at company-operated LNG

facilities.

During 2012, Chevron signed nonbinding Heads of Agreement with Tohoku Electric

and Chubu Electric and additional binding agreements with Tokyo Electric for LNG

offtake from the Wheatstone Project. To date, more than 80 percent of Chevron's

equity LNG from Wheatstone is covered under long-term agreements with

customers in Asia.

 Angola In early 2013, the company announced it plans to proceed with the

development of the Mafumeira Sul Project located in Block 0.

 Angola-Republic of the Congo Joint Development Area In third quarter

2012, the company reached a final investment decision on the cross-border

development of the deepwater Lianzi Field.

 Bangladesh In July 2012, the company reached a final investment decision on

the Bibiyana Expansion Project.

 Canada In February 2013, Chevron acquired a 50 percent-owned and operated

interest in the Kitimat LNG project and proposed Pacific Trail Pipeline, and a 50

percent nonoperated interest in approximately 644,000 acres in the Horn River and

Liard Basins.

 China In 2012, Chevron entered into an agreement to acquire two exploration

blocks in the South China Sea's Pearl River Mouth Basin. Government approval is

expected in 2013.

FS-5
Management's Discussion and Analysis of

Financial Condition and Results of Operations

 Kurdistan Region of Iraq In third quarter 2012, Chevron acquired an 80

percent interest and operatorship in the Rovi and Sarta blocks.

 Lithuania In October 2012, Chevron acquired a 50 percent interest in a

company with exploration interests in a shale gas block.

 Morocco In January 2013, the company announced that it had signed

agreements to explore three offshore areas.

 Nigeria In February 2012, production commenced at the deepwater Usan

project.

 Sierra Leone In September 2012, the company was awarded a 55 percent

interest and operatorship in two deepwater exploration blocks.

 Suriname In November 2012, the company acquired a 50 percent interest in

two offshore exploration blocks.

 Ukraine In second quarter 2012, the company bid successfully for the right to

exclusively negotiate a 50 percent interest and operatorship in a shale gas block.

 United Kingdom In July 2012, the company initiated front-end engineering and

design (FEED) for the deepwater Rosebank project west of the Shetland Islands.

 United States In October 2012, the company acquired additional acreage in New

Mexico. A major portion of the acreage is located in the Delaware Basin, where the

company is already one of the largest leaseholders.

In second quarter 2012, the company successfully bid for additional shelf and

deepwater exploration acreage in the central Gulf of Mexico. In fourth quarter 2012,

the company submitted high bids for additional deepwater acreage in the western Gulf

of Mexico.

In the first quarter 2012, production commenced at the Caesar/Tonga project in the

deepwater Gulf of Mexico.

Downstream

Caribbean During 2012, the company completed the sale of its fuels marketing and

aviation businesses in eight countries in the Caribbean.

 Europe During first quarter 2012, the company completed the sale of its fuels

marketing, finished lubricants and aviation businesses in Spain.

 Saudi Arabia In October 2012, the company's 50 percent-owned Chevron

Phillips Chemical Company LLC announced that its 35 percent-owned Saudi

Polymers Company began commercial production at its new petrochemical facility in

Al-Jubail.

 South Korea During 2012, the company's 50 percent-owned GS Caltex affiliate

completed the sale of certain power and other assets.

 United States In third quarter 2012, the company completed the sale of its idled

Perth Amboy, New Jersey, refinery, which had been operating as a terminal.

In April 2012, the company's 50 percent-owned Chevron Phillips Chemical Company

LLC announced the execution of FEED contracts for an ethane cracker at its Cedar

Bayou facility in Baytown, Texas, and two polyethylene facilities near its Sweeny

facility in Old Ocean, Texas.

Other

Common Stock Dividends The quarterly common stock dividend was increased

by 11.1 percent in April 2012 to $0.90 per common share, making 2012 the 25th

consecutive year that the company increased its annual dividend payment.

 Common Stock Repurchase Program The company purchased $5.0 billion

of its common stock in 2012 under its share repurchase program. The program

began in 2010 and has no set term or monetary limits.

Results of Operations

Major Operating Areas The following section presents the results of operations

for the company’s business segments – Upstream and Downstream – as well as for

“All Other.” Earnings are also presented for the U.S. and international geographic

areas of the Upstream and Downstream business segments. Refer to Note 10,

beginning on page FS-36, for a discussion of the company’s “reportable segments,”

as defined in accounting standards for segment reporting (Accounting Standards

Codification (ASC) 280). This section should also be read in conjunction with the

discussion in “Business Environment and Outlook” on pages FS-2 through FS-5.

U.S. Upstream

Millions of dollars 2012 2011 2010

Earnings $ 5,332 $ 6,512 $ 4,122

 U.S. upstream earnings of $5.3 billion in 2012 decreased $1.2 billion from

2011, primarily due to lower natural gas and crude oil realizations of $340 million

and $200 million, respectively, lower crude oil production of $240 million, and lower

gains on asset sales of $180 million.

 U.S. upstream earnings of $6.5 billion in 2011 increased $2.4 billion from 2010.

The benefit of higher crude oil realizations increased earnings by $2.8 billion between

periods. Partly offsetting this effect were lower net oil-equivalent production, which

decreased earnings by about $400 million, and higher operating expenses of

$200 million.

 The company’s average realization for U.S. crude oil and natural gas liquids in

2012 was $95.21 per barrel, compared with $97.51 in 2011 and $71.59 in 2010.

The average natural gas realization was $2.64 per thousand cubic feet in 2012,

compared with $4.04 and $4.26 in 2011 and 2010, respectively.

FS-6
 Net oil-equivalent production in 2012 averaged 655,000 barrels per day, down 3

percent from 2011 and 7 percent from 2010. Between 2012 and 2011, the decrease

in production was associated with normal field declines and an absence of volumes

associated with Cook Inlet, Alaska, assets sold in 2011. Partially offsetting this

decrease was a ramp-up of projects in the Gulf of Mexico and Marcellus Shale and

improved operational performance in the Gulf of Mexico. The net liquids component

of oil-equivalent production for 2012 averaged 455,000 barrels per day, down 2

percent from 2011 and 7 percent from 2010. Net natural gas production averaged

about 1.2 billion cubic feet per day in 2012, down approximately 6 percent from

2011 and about 8 percent from 2010. Refer to the “Selected Operating Data” table

on page FS-10 for a three-year comparative of production volumes in the United

States.

International Upstream

Millions of dollars 2012 2011 2010

Earnings* $ 18,456 $ 18,274 $ 13,555

*Includes foreign currency effects: $ (275) $ 211 $ (293)

 International upstream earnings were $18.5 billion in 2012 compared with $18.3

billion in 2011. The increase was mainly due to a gain of approximate $1.4 billion on

an asset exchange in Australia, higher natural gas realizations of about $610 million

and a nearly $600 million gain on sale of an equity interest in the Wheatstone Project.

Mostly offsetting these effects were lower crude oil volumes of about $1.3 billion and

higher exploration expenses of about $430 million. Foreign currency effects

decreased earnings by $275 million in 2012, compared with an increase of $211

million a year earlier.

 International upstream earnings of $18.3 billion in 2011 increased $4.7 billion

from 2010. Higher prices for crude oil increased earnings by $7.1 billion. This benefit

was partly offset by higher tax items of about $1.7 billion and higher operating

expenses, including fuel, of about $1.0 billion. Foreign currency effects increased

earnings by $211 million in 2011, compared with a decrease of $293 million in 2010.

 The company’s average realization for international crude oil and natural gas

liquids in 2012 was $101.88 per barrel, compared with $101.53 in 2011 and

$72.68 in 2010. The average natural gas realization was $5.99 per thousand cubic

feet in 2012, compared with $5.39 and $4.64 in 2011 and 2010, respectively.

 International net oil-equivalent production of 1.96 million barrels per day in 2012

decreased 2 percent from 2011 and decreased about 5 percent from 2010. New

production in Thailand and Nigeria in 2012 was more than offset by normal field

declines, the shut-in of the Frade field in Brazil and a major planned turnaround at

Tengizchevroil. The decline between 2011 and 2010 was primarily due to price effects

on entitlement volumes.

 The net liquids component of international oil-equivalent production was about

1.3 million barrels per day in 2012, a decrease of approximately 5 percent from 2011

and a decrease of approximately 9 percent from 2010. International net natural gas

production of 3.9 billion cubic feet per day in 2012 was up

6 percent from 2011 and up 4 percent from 2010. 

Refer to the “Selected Operating Data” table, on page FS-10, for a three-year

comparative of international production volumes.

U.S. Downstream

Millions of dollars 2012 2011 2010

Earnings $ 2,048 $ 1,506 $ 1,339

 U.S. downstream operations earned $2.0 billion in 2012, compared with $1.5

billion in 2011. The increase was mainly due to higher margins on refined product

sales of $520 million and higher earnings of $140 million from the 50 percent-owned

Chevron Phillips Chemical Company LLC (CPChem). These benefits were partly

offset by higher operating expenses of $130 million.

 Earnings of $1.5 billion in 2011 increased $167 million from 2010. Earnings

benefited by $300 million from improved margins on refined products, $200 million

from higher earnings from CPChem and $50 million from the absence of 2010

charges related to employee reductions. These benefits were partly offset by the

absence of a $400 million gain on the sale of the company’s ownership interest in the

Colonial Pipeline Company recognized in 2010.

 Refined product sales of 1.21 million barrels per day in 2012 declined 4 percent,

mainly reflecting lower gasoline and fuel oil sales. Sales volumes of refined products

were 1.26 million barrels per day in 2011, a decrease of 7 percent from 2010. The

decline was mainly in gasoline, gas oil and kerosene sales. U.S. branded gasoline sales

of 516,000 barrels per day in 2012 were essentially flat from 2011 and declined

approximately 10 percent from 2010. The decline in 2012 and

FS-7
Management's Discussion and Analysis of

Financial Condition and Results of Operations

2011 from 2010 was primarily due to weaker demand and previously completed exits

from selected eastern U.S. retail markets.

 Refer to the “Selected Operating Data” table on page FS-10 for a three-year

comparison of sales volumes of gasoline and other refined products and refinery

input volumes.

International Downstream

Millions of dollars 2012 2011 2010

Earnings* $ 2,251 $ 2,085 $ 1,139

*Includes foreign currency effects: $ (173) $ (65) $ (135)

 International downstream earned $2.3 billion in 2012, compared with $2.1 billion

in 2011. Earnings increased due to a favorable change in effects on derivative

instruments of $190 million and higher margins on refined product sales of $100

million. Foreign currency effects decreased earnings by $173 million in 2012,

compared with a decrease of $65 million a year earlier.

 Earnings of $2.1 billion in 2011 increased $946 million from 2010. Gains on asset

sales benefited earnings by $700 million, primarily from the sale of the Pembroke

Refinery and related marketing assets in the United Kingdom and Ireland. Also

contributing to earnings were improved margins of $200 million and the absence of

2010 charges of $90 million related to employee reductions. These benefits were

partly offset by an unfavorable change in effects on derivative instruments of about

$180 million. Foreign currency effects decreased earnings by $65 million in 2011,

compared with a decrease of $135 million in 2010.

 Total refined product sales of

1.55 million barrels per day in 2012

declined 8 percent, primarily related to

the third quarter 2011 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 flat

between the comparative periods.

International refined product sales

volumes of 1.69 million barrels per day

in 2011 were 4 percent lower than in

2010, primarily due 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 up 3 percent

between the comparative periods.

 Refer to the “Selected Operating Data” table, on page FS-10, for a three-year

comparison of sales volumes of gasoline and other refined products and refinery

input volumes.

All Other

Millions of dollars 2012 2011 2010

Net charges* $ (1,908) $ (1,482) $ (1,131)

*Includes foreign currency effects: $ (6) $ (25) $ 5

 All Other includes mining operations, power generation businesses, worldwide

cash management and debt financing activities, corporate administrative functions,

insurance operations, real estate activities, energy services, alternative fuels, and

technology companies.

 Net charges in 2012 increased 426 million from 2011, mainly due to higher

environmental reserve additions, corporate tax items and other corporate charges,

partially offset by lower employee compensation and benefits expenses.

 Net charges in 2011 increased $351 million from 2010, mainly due to higher

expenses for employee compensation and benefits and higher net corporate tax

expenses.

FS-8
Consolidated Statement of Income

Comparative amounts for certain income statement categories are shown below:

Millions of dollars 2012 2011 2010

Sales and other operating revenues $ 230,590 $ 244,371 $ 198,198

 Sales and other operating revenues decreased in 2012 mainly due to the 2011 sale

of the company’s refining and marketing assets in the United Kingdom and Ireland,

and lower crude oil volumes. Higher 2011 prices for crude oil and refined products

resulted in increased sales and other operating revenues compared with 2010.

Millions of dollars 2012 2011 2010

Income from equity affiliates $ 6,889 $ 7,363 $ 5,637

 Income from equity affiliates decreased in 2012 from 2011 mainly due to lower

upstream-related earnings from Tengizchevroil in Kazakhstan as a result of lower

crude oil production, and higher operating expenses at Angola LNG Limited and

Petropiar in Venezuela. Downstream-related earnings were higher between

comparative periods, primarily due to higher margins at CPChem.

 Income from equity affiliates increased in 2011 from 2010 mainly due to higher

upstream-related earnings from Tengizchevroil as a result of higher prices for crude

oil. Downstream-related earnings were also higher between the comparative periods,

primarily due to higher earnings from CPChem as a result of higher margins on sales

of commodity chemicals.

Refer to Note 11, beginning on page FS-38, for a discussion of Chevron’s

investments in affiliated companies.

Millions of dollars 2012 2011 2010

Other income $ 4,430 $ 1,972 $ 1,093

 Other income of $4.4 billion in 2012 included net gains from asset sales of

approximately $4.2 billion. Other income in both 2011 and 2010 included net gains

from asset sales of $1.5 billion and $1.1 billion, respectively. Interest income was

approximately $166 million in 2012, $145 million in 2011 and $120 million in 2010.

Foreign currency effects decreased other income by $207 million in 2012, while

increasing other income by $103 million in 2011 and decreasing other income by

$251 million in 2010.

Millions of dollars 2012 2011 2010

Purchased crude oil and products $ 140,766 $ 149,923 $ 116,467

Crude oil and product purchases of $140.8 billion were down in 2012 mainly due to

the 2011 sale of the company’s refining and marketing assets in the United Kingdom

and Ireland and lower natural gas prices. Crude oil and product purchases in 2011

increased by $33.5 billion from the prior year due to higher prices for crude oil,

natural gas and refined products.

Millions of dollars 2012 2011 2010

Operating, selling, general and

 administrative expenses $ 27,294 $ 26,394 $ 23,955

 Operating, selling, general and administrative expenses increased $900 million

between 2012 and 2011 mainly due to higher contract labor and professional services

of $590 million, and higher employee compensation and benefits of $280 million.

 Operating, selling, general and administrative expenses increased $2.4 billion

between 2011 and 2010. This increase was primarily related to higher fuel expenses

of $1.5 billion and higher employee compensation and benefits of $700 million. In

part, increased fuel purchases in 2011 reflected a new commercial arrangement that

replaced a prior product exchange agreement for upstream operations in Indonesia.

Millions of dollars 2012 2011 2010

Exploration expense $ 1,728 $ 1,216 $ 1,147

 Exploration expenses in 2012 increased from 2011 mainly due to higher geological

and geophysical costs and well write-offs.

 Exploration expenses in 2011 increased from 2010 mainly due to higher geological

and geophysical costs, partly offset by lower well write-offs.

Millions of dollars 2012 2011 2010

Depreciation, depletion and

 amortization $ 13,413 $ 12,911 $ 13,063

 The increase in 2012 from 2011 was mainly due to higher depreciation rates for

certain oil and gas producing fields, partially offset by lower production levels. The

decrease in 2011 from 2010 mainly reflected lower production levels and the 2011

sale of the Pembroke Refinery, partially offset by higher depreciation rates for certain

oil and gas producing fields.

Millions of dollars 2012 2011 2010

Taxes other than on income $ 12,376 $ 15,628 $ 18,191

 Taxes other than on income decreased in 2012 from 2011 primarily due to lower

import duties in the United Kingdom reflecting the sale of the company’s refining and

marketing assets in the United Kingdom and Ireland in 2011. Partially offsetting the

decrease were excise taxes associated with consolidation of Star Petroleum Refining

Company beginning June 2012. Taxes other than on income decreased in 2011 from

2010 primarily due to lower import duties in the United Kingdom reflecting the 2011

sale of the Pembroke Refinery and other downstream assets, partly offset by higher

excise taxes in the company’s South Africa downstream operations.

Millions of dollars 2012 2011 2010

Interest and debt expense $ — $ — $ 50

 Total interest and debt expenses were fully capitalized in 2012 and 2011.

FS-9
Management's Discussion and Analysis of

Financial Condition and Results of Operations

Millions of dollars 2012 2011 2010

Income tax expense $ 19,996 $ 20,626 $ 12,919

 Effective income tax rates were 43 percent in 2012, 43 percent in 2011 and 40

percent in 2010. The rate was unchanged between 2012 and 2011. The impact of

lower effective tax rates in international upstream operations were offset by foreign

currency remeasurement impacts between periods. For international upstream, the

lower effective tax rates in the current period were driven primarily by the effects of

asset sales, one-time tax benefits and reduced withholding taxes, which were partially

offset by a lower utilization of tax credits during the year. The rate was higher in

2011 than in 2010 primarily due to higher effective tax rates in certain international

upstream jurisdictions. The higher international upstream effective tax rates were

driven primarily by lower utilization of non-U.S. tax credits in 2011 and the effect of

changes in income tax rates between periods, which were partially offset by foreign

currency remeasurement impacts.

Selected Operating Data1,2

2012 2011 2010

U.S. Upstream

Net Crude Oil and Natural Gas

Liquids Production (MBPD) 455 465 489

Net Natural Gas Production (MMCFPD) 3 1,203 1,279 1,314

Net Oil-Equivalent Production (MBOEPD) 655 678 708

Sales of Natural Gas (MMCFPD) 5,470 5,836 5,932

Sales of Natural Gas Liquids (MBPD) 16 15 22

Revenues From Net Production

Liquids ($/Bbl) $ 95.21 $ 97.51 $ 71.59

Natural Gas ($/MCF) $ 2.64 $ 4.04 $ 4.26

International Upstream

Net Crude Oil and Natural Gas

Liquids Production (MBPD) 4 1,309 1,384 1,434

Net Natural Gas Production (MMCFPD) 3 3,871 3,662 3,726

Net Oil-Equivalent Production (MBOEPD)

Production (MBOEPD)4 1,955 1,995 2,055

Sales of Natural Gas (MMCFPD) 4,315 4,361 4,493

Sales of Natural Gas Liquids (MBPD) 24 24 27

Revenues From Liftings

Liquids ($/Bbl) $ 101.88 $ 101.53 $ 72.68

Natural Gas ($/MCF) $ 5.99 $ 5.39 $ 4.64

Worldwide Upstream

Net Oil-Equivalent Production (MBOEPD) 4

United States 655 678 708

International 1,955 1,995 2,055

Total 2,610 2,673 2,763

U.S. Downstream

Gasoline Sales (MBPD)5 624 649 700

Other Refined Product Sales (MBPD) 587 608 649

Total Refined Product Sales (MBPD) 1,211 1,257 1,349

Sales of Natural Gas Liquids (MBPD) 141 146 139

Refinery Input (MBPD) 833 854 890

International Downstream

Gasoline Sales (MBPD)5 412 447 521

Other Refined Product Sales (MBPD) 1,142 1,245 1,243

Total Refined Product Sales (MBPD)6 1,554 1,692 1,764

Sales of Natural Gas Liquids (MBPD) 64 63 78

Refinery Input (MBPD) 7 869 933 1,004

1

Includes company share of equity affiliates.

2 MBPD – thousands of barrels per day; MMCFPD – millions of cubic feet per day; MBOEPD –

thousands of barrels of oil-equivalents per day; Bbl – Barrel; MCF = Thousands of cubic feet. Oilequivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of oil.

3

Includes natural gas consumed in operations (MMCFPD):

 United States 63 69 62

 International 523 513 475

4

 Includes: Canada – synthetic oil 43 40 24

Venezuela affiliate – synthetic oil 17 32 28

5

 Includes branded and unbranded gasoline.

6

 Includes sales of affiliates (MBPD): 522 556 562

7 As of June 2012, Star Petroleum Refining Company crude-input volumes are reported on a 100

percent consolidated basis. Prior to June 2012, crude-input volumes reflect a 64 percent equity

interest.
FS-10
Liquidity and Capital Resources

Cash, cash equivalents, time deposits and marketable securities Total

balances were $21.9 billion and $20.1 billion at December 31, 2012 and 2011,

respectively. Cash provided by operating activities in 2012 was $38.8 billion,

compared with $41.1 billion in 2011 and $31.4 billion in 2010. Cash provided by

operating activities was net of contributions to employee pension plans of

approximately $1.2 billion, $1.5 billion and $1.4 billion in 2012, 2011 and 2010,

respectively. Cash provided by investing activities included proceeds and deposits

related to asset sales of $2.7 billion in 2012, $3.5 billion in 2011, and $2.0 billion in

2010.

 Restricted cash of $1.5 billion and $1.2 billion associated with tax payments,

upstream abandonment activities, funds held in escrow for an asset acquisition and

capital investment projects at December 31, 2012 and 2011, respectively, was

invested in short-term marketable securities and recorded as “Deferred charges and

other assets” on the Consolidated Balance Sheet.

 Dividends Dividends paid to common stockholders were $6.8 billion in 2012,

$6.1 billion in 2011 and $5.7 billion in 2010. In April 2012, the company increased

its quarterly dividend by 11.1 percent to 90 cents per common share.

Debt and capital lease obligations Total debt and capital lease obligations were

$12.2 billion at December 31, 2012, up from $10.2 billion at year-end 2011.

 The $2.0 billion increase in total debt and capital lease obligations during 2012

included the net effect of a $4 billion bond issuance and the early redemption of a $2

billion bond due in March 2014. 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 $6.0 billion at

December 31, 2012, compared with $5.9 billion at year-end 2011. Of these

amounts, $5.9 billion and $5.6 billion were reclassified to long-term at the end of

each period, respectively. At year-end 2012, settlement of these obligations was not

expected to require the use of working capital in 2013, as the company had the intent

and the ability, as evidenced by committed credit facilities, to refinance them on a

long-term basis.

 At December 31, 2012, the company had $6.0 billion in committed credit facilities

with various major banks, expiring in December 2016, 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 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 December 31, 2012. In addition, in November 2012, the company filed

with the Securities and Exchange Commission a new registration statement that

expires in November 2015. This registration statement is 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 & Poor’s Corporation and Aa1 by

Moody’s Investors Service. The company’s U.S. commercial paper is rated A-1+ by

Standard & Poor’s and P-l 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 any

extended 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 stock 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

2012, the company purchased 46.6 million common shares for $5.0 billion. From

the inception of the program through

FS-11
Management's Discussion and Analysis of

Financial Condition and Results of Operations

Capital and Exploratory Expenditures

2012 2011 2010

Millions of dollars U.S. Int’l. Total U.S. Int’l. Total U.S. Int’l. Total

Upstream1 $ 8,531 $ 21,913 $ 30,444 $ 8,318 $ 17,554 $ 25,872 $ 3,450 $ 15,454 $ 18,904

Downstream 1,913 1,259 3,172 1,461 1,150 2,611 1,456 1,096 2,552

All Other 602 11 613 575 8 583 286 13 299

Total $ 11,046 $ 23,183 $ 34,229 $ 10,354 $ 18,712 $ 29,066 $ 5,192 $ 16,563 $ 21,755

Total, Excluding Equity in Affiliates $ 10,738 $ 21,374 $ 32,112 $ 10,077 $ 17,294 $ 27,371 $ 4,934 $ 15,433 $ 20,367

1

 Excludes the acquisition of Atlas Energy, Inc., in 2011.

2012, the company had purchased 97.7 million shares for $10.0 billion.

 Capital and exploratory expenditures Total expenditures for 2012 were

$34.2 billion, including $2.1 billion for the company’s share of equity-affiliate

expenditures. In 2011 and 2010, expenditures were $29.1 billion and $21.8 billion,

respectively, including the company’s share of affiliates’ expenditures of $1.7 billion

and $1.4 billion, respectively.

 Of the $34.2 billion of expenditures in 2012, 89 percent, or $30.4 billion, was

related to upstream activities. Approximately 89 percent and 87 percent were

expended for upstream operations in 2011 and 2010. International upstream

accounted for about 72 percent of the worldwide upstream investment in 2012,

about 68 percent in 2011 and about 82 percent in 2010. These amounts exclude the

acquisition of Atlas Energy, Inc., in 2011.

 The company estimates that 2013 capital and exploratory expenditures will be

$36.7 billion, including $3.3 billion of

spending by affiliates. Approximately 90 percent of the total, or $33 billion, is

budgeted for exploration and production activities. Approximately $25.5 billion, or

77 percent, of this amount is for projects outside the United States. Spending in

2013 is primarily focused on major development projects in Angola, Australia,

Brazil, Canada, China, Kazakhstan, Nigeria, Republic of Congo, Russia, the United

Kingdom and the U.S. Gulf of Mexico. Also included is funding for enhancing

recovery and mitigating natural field declines for currently-producing assets, and for

focused exploration and appraisal activities.

 Worldwide downstream spending in 2013 is estimated at $2.7 billion, with about

$1.4 billion for projects in the United States. Major capital outlays include projects

under construction at refineries in the United States, expansion of additives

production capacity in Singapore and chemicals projects in the United States.

 Investments in technology companies, power generation and other corporate

businesses in 2013 are budgeted at $1 billion.

 Noncontrolling interests The company had noncontrolling interests of $1,308

million and $799 million at December 31, 2012 and 2011, respectively. Distributions

to noncontrolling interests totaled $41 million and $71 million in 2012 and 2011,

respectively.

 

Pension Obligations Information related to pension plan contributions is included

on page FS-54 in Note 20 to the Consolidated Financial Statements under the

heading “Cash Contributions and Benefit Payments.” Refer also to the discussion of

pension accounting in “Critical Accounting Estimates and Assumptions,” beginning

on page FS-16.

FS-12
Financial Ratios

Financial Ratios

At December 31

2012 2011 2010

Current Ratio 1.6 1.6 1.7

Interest Coverage Ratio 191.3 165.4 101.7

Debt Ratio 8.2 % 7.7 % 9.8 %

 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 in all periods was adversely affected by the fact that Chevron’s

inventories are valued on a last-in, first-out basis. At year-end 2012, the book value

of inventory was lower than replacement costs, based on average acquisition costs

during the year, by approximately $9.3 billion.

 Interest Coverage Ratio – income before income tax expense, plus interest

and debt expense and amortization of capitalized interest, less net income attributable

to noncontrolling interests, divided by before-tax interest costs. This ratio indicates

the company’s ability to pay interest on outstanding debt. The company’s interest

coverage ratio in 2012 was higher than 2011 and 2010 due to lower before-tax

interest costs.

 Debt Ratio – total debt as a percentage of total debt plus Chevron Corporation

Stockholders' Equity, which indicates the company’s leverage. The increase between

2012 and 2011 was due to higher debt, partially offset by a higher Chevron

Corporation stockholders' equity balance. The decrease between 2011 and 2010 was

due to a higher Chevron Corporation stockholders' equity balance.

Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and

Other Contingencies

Direct Guarantees

Millions of dollars Commitment Expiration by Period

2014– 2016– After

Total 2013 2015 2017 2017

Guarantee of non- consolidated

affiliate or joint-venture

obligations $562 $38 $76 $76 $372

 The company’s guarantee of $562 million is associated with certain payments

under a terminal use agreement entered into by an equity affiliate. Over the

approximate 15-year remaining term of the guarantee, the maximum guarantee

amount will be reduced as certain fees are paid by the affiliate. There are numerous

cross-indemnity agreements with the affiliate and the other partners to permit

recovery of amounts paid under the guarantee. Chevron has recorded no liability for

its obligation under this guarantee.

 Indemnifications Information related to indemnifications is included on page

FS-56 in Note 22 to the Consolidated Financial Statements under the heading

“Indemnifications.”

 Long-Term Unconditional Purchase Obligations and Commitments,

Including Throughput and Take-or-Pay

Agreements 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. The aggregate

approximate amounts of required payments under these various commitments are:

2013 – $3.7 billion; 2014 – $3.9 billion; 2015 – $4.1 billion; 2016 – $2.4 billion;

2017 – $1.8 billion; 2018 and after – $6.5 billion. A portion of these commitments

may ultimately be shared with project partners. Total payments under the agreements

were approximately $3.6 billion in 2012, $6.6 billion in 2011 and $6.5 billion in

2010.

 The following table summarizes the company’s significant contractual obligations:

Contractual Obligations 1

Millions of dollars Payments Due by Period

2014– 2016– After

Total 2013 2015 2017 2017

On Balance Sheet:2

Short-Term Debt3 $ 127 $ 127 $ — $ — $ —

Long-Term Debt3 11,966 — 5,923 2,000 4,043

Noncancelable Capital

Lease Obligations 189 45 60 25 59

Interest 1,983 210 408 402 963

Off Balance Sheet:

Noncancelable Operating

Lease Obligations 3,548 727 1,276 929 616

Throughput and Take-orPay Agreements4 17,164 2,705 5,480 2,904 6,075

Other Unconditional

Purchase Obligations4 5,285 1,003 2,470 1,342 470

1 Excludes contributions for pensions and other postretirement benefit plans. Information

on employee benefit plans is contained in Note 20 beginning on page FS-49.

2 Does not include amounts related to the company’s income tax liabilities associated with

uncertain tax positions. The company is unable to make reasonable estimates of the

periods in which these liabilities may become payable. The company does not expect

settlement of such liabilities will have a material effect on its consolidated financial

position or liquidity in any single period.

3 $5.9 billion of short-term debt that the company expects to refinance is included in

long-term debt. The repayment schedule above reflects the projected repayment of the

entire amounts in the 2014–2015 period.

4 Does not include commodity purchase obligations that are not fixed or determinable.

These obligations are generally monetized in a relatively short period of time through

sales transactions or similar agreements with third parties. Examples include obligations

to purchase LNG, regasified natural gas and refinery products at indexed prices.

FS-13
Management's Discussion and Analysis of

Financial Condition and Results of Operations

Financial and Derivative Instruments

The market risk associated with the company’s portfolio of financial and derivative

instruments is discussed below. The estimates of financial exposure to market risk do

not represent the company’s projection of future market changes. The actual impact

of future market changes could differ materially due to factors discussed elsewhere in

this report, including those set forth under the heading “Risk Factors” in Part I,

Item 1A, of the company’s 2012 Annual Report on Form 10-K.

 Derivative Commodity Instruments Chevron is exposed to market risks

related to the price volatility of crude oil, refined products, natural gas, natural gas

liquids, liquefied natural gas and refinery feedstocks.

 The company uses derivative commodity instruments to manage these exposures

on a portion of its activity, including firm commitments and anticipated transactions

for the purchase, sale and storage of crude oil, refined products, natural gas, natural

gas liquids and feedstock for company refineries. The company also uses derivative

commodity instruments for limited trading purposes. The results of these activities

were not material to the company’s financial position, results of operations or cash

flows in 2012.

 The company’s market exposure positions are monitored and managed on a daily

basis by an internal Risk Control group in accordance with the company’s risk

management policies, which have been approved by the Audit Committee of the

company’s Board of Directors.

 The derivative commodity instruments used in the company’s risk management

and trading activities consist mainly of futures, options and swap contracts traded on

the New York Mercantile Exchange and on electronic platforms of the InterContinental Exchange and Chicago Mercantile Exchange. In addition, crude oil,

natural gas and refined product swap contracts and option contracts are entered into

principally with major financial institutions and other oil and gas companies in the

“over-the-counter” markets.

 Derivatives beyond those designated as normal purchase and normal sale contracts

are recorded at fair value on the Consolidated Balance Sheet in accordance with

accounting standards for derivatives (ASC 815), with resulting gains and losses

reflected in income. Fair values are derived principally from published market quotes

and other independent third-party quotes. The change in fair value of Chevron’s

derivative commodity instruments in 2012 was a quarterly average decrease of

$31 million in total assets and a quarterly average increase of $12 million in total

liabilities.

 The company uses a Value-at-Risk (VaR) model to estimate the potential loss in

fair value on a single day from the effect of adverse changes in market conditions on

derivative commodity instruments held or issued. VaR is the maximum projected

loss not to be exceeded within a given probability or confidence level over a given

period of time. The company’s VaR model uses the Monte Carlo simulation method

that involves generating hypothetical scenarios from the specified probability

distributions and constructing a full distribution of a portfolio’s potential values.

 The VaR model utilizes an exponentially weighted moving average for computing

historical volatilities and correlations, a 95 percent confidence level, and a one-day

holding period. That is,

the company’s 95 percent, one-day VaR corresponds to the unrealized loss in

portfolio value that would not be exceeded on average more than one in every 20

trading days, if the portfolio were held constant for one day.

 The one-day holding period is based on the assumption that market-risk positions

can be liquidated or hedged within one day. For hedging and risk management, the

company uses conventional exchange-traded instruments such as futures and options

as well as non-exchange-traded swaps, most of which can be liquidated or hedged

effectively within one day. The following table presents the 95 percent/one-day VaR

for each of the company’s primary risk exposures in the area of derivative

commodity instruments at December 31, 2012 and 2011.

Millions of dollars 2012 2011

Crude Oil $ 3 $ 22

Natural Gas 3 4

Refined Products 12 11

 Foreign Currency The company may enter into foreign currency derivative

contracts to manage some of its foreign currency exposures. These exposures

include revenue and anticipated purchase transactions, including foreign currency

capital expenditures and lease commitments. The foreign currency derivative

contracts, if any, are recorded at fair value on the balance sheet with resulting gains

and losses reflected in income. There were no open foreign currency derivative

contracts at December 31, 2012.

 Interest Rates The company may enter into interest rate swaps from time to

time as part of its overall strategy to manage the interest rate risk on its debt. Interest

rate swaps, if any, are recorded at fair value on the balance sheet with resulting gains

and losses reflected in income. At year-end 2012, the company had no interest rate

swaps.

FS-14
Transactions With Related Parties

Chevron enters into a number of business arrangements with related parties,

principally its equity affiliates. These arrangements include long-term supply or

offtake agreements and long-term purchase agreements. Refer to “Other

Information” in Note 11 of the Consolidated Financial Statements, page FS-39, for

further discussion. Management believes these agreements have been negotiated on

terms consistent with those that would have been negotiated with an unrelated party.

Litigation and Other Contingencies

MTBE Information related to methyl tertiary butyl ether (MTBE) matters is

included on page FS-40 in Note 13 to the Consolidated Financial Statements under

the heading “MTBE.”

 Ecuador Information related to Ecuador matters is included in Note 13 to the

Consolidated Financial Statements under the heading “Ecuador,” beginning on page

FS-40.

 Environmental The following table displays the annual changes to the

company’s before-tax environmental remediation reserves, including those for federal

Superfund sites and analogous sites under state laws.

Millions of dollars 2012 2011 2010

Balance at January 1 $ 1,404 $ 1,507 $ 1,700

Net Additions 428 343 220

Expenditures (429) (446) (413)

Balance at December 31 $ 1,403 $ 1,404 $ 1,507

 The company records asset retirement obligations when there is a legal obligation

associated with the retirement of long-lived assets and the liability can be reasonably

estimated. These asset retirement obligations include costs related to environmental

issues. The liability balance of approximately $13.3 billion for asset retirement

obligations at year-end 2012 related primarily to upstream properties.

 For the company’s other ongoing operating assets, such as refineries and

chemicals facilities, no provisions are made for exit or cleanup costs that may be

required when such assets reach the end of their useful lives unless a decision to sell

or otherwise abandon the facility has been made, as the indeterminate settlement dates

for the asset retirements prevent estimation of the fair value of the asset retirement

obligation.

 Refer to the discussion below for additional information on environmental matters

and their impact on Chevron, and on the company's 2012 environmental

expenditures. Refer to Note 22 on pages FS-56 through FS-57 for additional

discussion of environmental remediation provisions and year-end reserves. Refer also

to Note 23 on page FS-58 for additional discussion of the company's asset retirement

obligations.

 Suspended Wells Information related to suspended wells is included in Note 18

to the Consolidated Financial Statements, Accounting for Suspended Wells,

beginning on page FS-47.

 Income Taxes Information related to income tax contingencies is included on

pages FS-43 through FS-45 in Note 14 and pages FS-55 through FS-56 in Note

22 to the Consolidated Financial Statements under the heading “Income Taxes.”

The American Taxpayer Relief Act of 2012 (the Act) was signed into U.S.

law on January 2, 2013. Several tax provisions that expired at the end of

2011 were extended retroactive to January 1, 2012, including the research

and development credit and certain rules for controlled foreign corporations.

There were no impacts from the Act included in Chevron's 2012 financial

statements and the company does not expect the impacts of the Act to have a

material effect on its results of operations, consolidated financial position or

liquidity in any future reporting period. 

 Other Contingencies Information related to other contingencies is included on

page FS-57 in Note 22 to the Consolidated Financial Statements under the heading

“Other Contingencies.”

Environmental Matters

Virtually all aspects of the businesses in which the company engages are subject to

various international, federal, state and local environmental, health and safety laws,

regulations and market-based programs. These regulatory requirements continue to

increase in both number and complexity over time and govern not only the manner in

which the company conducts its operations, but also the products it sells.

Regulations intended to address concerns about greenhouse gas emissions and global

climate change also continue to evolve and include those at the international or

multinational (such as the mechanisms under the Kyoto Protocol and the European

Union's Emissions Trading System), national (such as the U.S. Environmental

Protection Agency's emission standards and renewable transportation fuel content

requirements or domestic market-based programs such as those in effect in Australia

and New Zealand), and state or regional (such as California's Global Warming

Solutions Act) levels.

Most of the costs of complying with laws and regulations pertaining to company

operations and products are embedded in the normal costs of doing business. It is not

possible to predict with certainty the amount of additional investments in new or

existing facilities or amounts of incremental operating costs to be incurred in the

future to: prevent, control, reduce or eliminate releases of hazardous materials into

the environment; comply with existing and new environmental laws or regulations; or

remediate and restore areas damaged by prior releases of hazardous materials.

Although these costs may be significant to the results of operations in any single

period, the company does not expect them to have a material effect on the company's

liquidity or financial position.

 Accidental leaks and spills requiring cleanup may occur in the ordinary course of

business. In addition to the costs for environmental protection associated with its

ongoing operations and products, the company may incur expenses for corrective

actions at various owned and previously owned facilities and at third-party-owned

waste disposal sites used by the company. An obligation may arise when operations

are closed or sold or at non-Chevron sites where company products have been

handled or disposed of. Most of the

FS-15
Management's Discussion and Analysis of

Financial Condition and Results of Operations

expenditures to fulfill these obligations relate to facilities and sites where past

operations followed practices and procedures that were considered acceptable at the

time but now require investigative or remedial work or both to meet current

standards.

 Using definitions and guidelines established by the American Petroleum Institute,

Chevron estimated its worldwide environmental spending in 2012 at approximately

$2.8 billion for its consolidated companies. Included in these expenditures were

approximately $1.1 billion of environmental capital expenditures and $1.7 billion of

costs associated with the prevention, control, abatement or elimination of hazardous

substances and pollutants from operating, closed or divested sites, and the

abandonment and restoration of sites.

 For 2013, total worldwide environmental capital expenditures are estimated at

$1.2 billion. These capital costs are in addition to the ongoing costs of complying with

environmental regulations and the costs to remediate previously contaminated sites.

Critical Accounting Estimates and Assumptions

Management makes many estimates and assumptions in the application of generally

accepted accounting principles (GAAP) that may have a material impact on the

company’s consolidated financial statements and related disclosures and on the

comparability of such information over different reporting periods. All such estimates

and assumptions affect reported amounts of assets, liabilities, revenues and expenses,

as well as disclosures of contingent assets and liabilities. Estimates and assumptions

are based on management’s experience and other information available prior to the

issuance of the financial statements. Materially different results can occur as

circumstances change and additional information becomes known.

 The discussion in this section of “critical” accounting estimates and

assumptions is according to the disclosure guidelines of the Securities and Exchange

Commission (SEC), wherein:

1. the nature of the estimates and assumptions is material due to the levels of

subjectivity and judgment necessary to account for highly uncertain

matters or the susceptibility of such matters to change; and

2. the impact of the estimates and assumptions on the company’s financial

condition or operating performance is material.

The development and selection of accounting estimates and assumptions, including

those deemed “critical,” and the associated disclosures in this discussion have been

discussed by management with the Audit Committee of the Board of Directors. The

areas of accounting and the associated “critical” estimates and assumptions made by

the company are as follows:

 Pension and Other Postretirement Benefit Plans The determination of

pension plan obligations and expense is based on a number of actuarial assumptions.

Two critical assumptions are the expected long-term rate of return on plan assets and

the discount rate applied to pension plan obligations. For other postretirement benefit

(OPEB) plans, which provide for certain health care and life insurance benefits for

qualifying retired employees and which are not funded, critical assumptions in

determining OPEB obligations and expense are the discount rate and the assumed

health care cost-trend rates.

 Note 20, beginning on page FS-49, includes information on the funded status of

the company’s pension and OPEB plans at the end of 2012 and 2011; the

components of pension and OPEB expense for the three years ended December 31,

2012; and the underlying assumptions for those periods.

 Pension and OPEB expense is reported on the Consolidated Statement of Income

as “Operating expenses” or “Selling, general and administrative expenses” and applies

to all business segments. The year-end 2012 and 2011 funded status, measured as

the difference between plan assets and obligations, of each of the company’s pension

and OPEB plans is recognized on the Consolidated Balance Sheet. The differences

related to overfunded pension plans are reported as a long-term asset in “Deferred

charges and other assets.” The differences associated with underfunded or unfunded

pension and OPEB plans are reported as “Accrued liabilities” or “Reserves for

employee benefit plans.” Amounts yet to be recognized as components of pension or

OPEB expense are reported in “Accumulated other comprehensive loss.”

 To estimate the long-term rate of return on pension assets, the company uses a

process that incorporates actual historical asset-class returns and an assessment of

expected future performance and takes into consideration external actuarial advice and

asset-class factors. Asset allocations are periodically updated using pension plan

asset/liability studies, and the determination of the company’s estimates of long-term

rates of return are consistent with these studies. For 2012, the company used an

expected long-term rate of return of 7.5 percent for U.S. pension plan assets, which

account for 70 percent of the company’s pension plan assets. In 2011 and 2010, the

company used a long-term rate of return of 7.8 percent for this plan. For the

10 years ending December 31, 2012, actual asset returns averaged 7.1 percent for

this plan. The actual return for 2012 was more than 7.5 percent and was associated

with a broad recovery in the financial markets during the year. Additionally, with the

exception of two other years within this 10-year period, actual asset returns for this

plan equaled or exceeded 7.5 percent.

FS-16
 The year-end market-related value of assets of the major U.S. pension plan used

in the determination of pension expense was based on the market value in the

preceding three months. Management considers the three-month period long enough

to minimize the effects of distortions from day-to-day market volatility and still be

contemporaneous to the end of the year. For other plans, market value of assets as

of year-end is used in calculating the pension expense.

 The discount rate assumptions used to determine the U.S. and international

pension and postretirement benefit plan obligations and expense reflect the at which

benefits could be effectively settled and is equal to the equivalent single rate resulting

from yield curve analysis. This analysis considered the projected benefit payments

specific to the company's plans and the yields on high-quality bonds. At December 31,

2012, the company used a 3.6 percent discount rate for the U.S. pension plans and

3.9 percent for the main U.S. OPEB plan. The discount rates at the end of 2011 and

2010 were 3.8 and 4.0 percent and 4.8 and 5.0 percent for the U.S. pension plans

and the main U.S. OPEB plans, respectively.

 An increase in the expected long-term return on plan assets or the discount rate

would reduce pension plan expense, and vice versa. Total pension expense for 2012

was $1.3 billion. As an indication of the sensitivity of pension expense to the longterm rate of return assumption, a 1 percent increase in the expected rate of return on

assets of the company’s primary U.S. pension plan would have reduced total pension

plan expense for 2012 by approximately $80 million. A 1 percent increase in the

discount rate for this same plan, which accounted for about 62 percent of the

companywide pension obligation, would have reduced total pension plan expense for

2012 by approximately $165 million.

 An increase in the discount rate would decrease the pension obligation, thus

changing the funded status of a plan reported on the Consolidated Balance Sheet.

The aggregate funded status recognized on the Consolidated Balance Sheet at

December 31, 2012, was a net liability of approximately $ 5.9 billion. As an indication

of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent

increase in the discount rate applied to the company’s primary U.S. pension plan

would have reduced the plan obligation by approximately $335 million, which would

have decreased the plan’s underfunded status from approximately $2.6 billion to

$2.2 billion. Other plans would be less underfunded as discount rates increase. The

actual rates of return on plan assets and discount rates may vary significantly from

estimates because of unanticipated changes in the world’s financial markets.

 In 2012, the company’s pension plan contributions were $1.2 billion (including

$844 million to the U.S. plans). In 2013, the company estimates contributions will

be approximately $1.0 billion. Actual contribution amounts are dependent upon

investment results, changes in pension obligations, regulatory requirements and

other economic factors. Additional funding may be required if investment returns are

insufficient to offset increases in plan obligations.

 For the company’s OPEB plans, expense for 2012 was $172 million, and the

total liability, which reflected the unfunded status of the plans at the end of 2012, was

$3.8 billion.

As an indication of discount rate sensitivity to the determination

of OPEB expense in 2012, a 1 percent increase in the discount rate for the company’s

primary U.S. OPEB plan, which accounted for about 82 percent of the

companywide OPEB expense, would have decreased OPEB expense by approximately

$17 million. A 0.25 percent increase in the discount rate for the same plan, which

accounted for about 83 percent of the companywide OPEB liabilities, would have

decreased total OPEB liabilities at the end of 2012 by approximately $80 million.

 For the main U.S. postretirement medical plan, the annual increase to company

contributions is limited to 4 percent per year. For active employees and retirees under

age 65 whose claims experiences are combined for rating purposes, the assumed

health care cost-trend rates start with 7.5 percent in 2013 and gradually drop to 4.5

percent for 2025 and beyond. As an indication of the health care cost-trend rate

sensitivity to the determination of OPEB expense in 2012, a 1 percent increase in the

rates for the main U.S. OPEB plan, would have increased OPEB expense by

$15 million.

 Differences between the various assumptions used to determine expense and the

funded status of each plan and actual experience are not included in benefit plan costs

in the year the difference occurs. Instead, the differences are included in actuarial

gain/loss and unamortized amounts have been reflected in “Accumulated other

comprehensive loss” on the Consolidated Balance Sheet. Refer to Note 20, beginning

on page FS-49, for information on the $ 9.7 billion of before-tax actuarial losses

recorded by the company as of December 31, 2012; a description of the method

used to amortize those costs; and an estimate of the costs to be recognized in expense

during 2013.

 Oil and Gas Reserves Crude oil and natural gas reserves are estimates of

future production that impact certain asset and expense accounts included in the

Consolidated Financial Statements. Proved reserves are the estimated quantities of oil

and gas that geoscience and engineering data demonstrate with reasonable certainty to

be economically producible in the future under existing economic conditions,

operating methods and government regulations. Proved reserves include both

developed and undeveloped volumes. Proved developed reserves represent volumes

expected to be recovered through existing wells with existing equipment and

operating methods. Proved undeveloped reserves are volumes expected to be

recovered from new wells on undrilled proved acreage, or from existing wells where

a relatively major expenditure is required for recompletion. Variables impacting

Chevron's estimated volumes of crude oil and natural gas reserves include field

performance, available technology and economic conditions.

FS-17
Management's Discussion and Analysis of

Financial Condition and Results of Operations

The estimates of crude oil and natural gas reserves are important to the timing of

expense recognition for costs incurred and to the valuation of certain oil and gas

producing assets. Impacts of oil and gas reserves on Chevron's Consolidated Financial

Statements, using the successful efforts method of accounting, include the following:

1. Amortization - Proved reserves are used in amortizing capitalized costs related to

oil and gas producing activities on the unit-of-production (UOP) method.

Capitalized exploratory drilling and development costs are depreciated on a UOP

basis using proved developed reserves. Acquisition costs of proved properties

are amortized on a UOP basis using total proved reserves. During 2012,

Chevron's UOP Depreciation, Depletion and Amortization (DD&A) for oil and

gas properties was $10.7 billion, and proved developed reserves at the beginning

of 2012 were 4.8 billion barrels. If the estimates of proved reserves used in the

UOP calculations for consolidated operations had been lower by 5 percent across

all oil and gas properties, UOP DD&A in 2012 would have increased by

approximately $540 million.

2. Impairment - Oil and gas reserves are used in assessing oil and gas producing

properties for impairment. A significant reduction in the estimated reserves of a

property would trigger an impairment review. In assessing whether the property

is impaired, the fair value of the property must be determined. Frequently, a

discounted cash flow methodology is the best estimate of fair value. Proved

reserves (and, in some cases, a portion of unproved resources) are used to

estimate future production volumes in the cash flow model. For a further

discussion of estimates and assumptions used in impairment assessments, see

Impairment of Properties, Plant and Equipment and Investments in

Affiliates below.

Refer to Table V, “Reserve Quantity Information,” beginning on page FS-67, for

the changes in proved reserve estimates for the three years ending December 31,

2012, and to Table VII, “Changes in the Standardized Measure of Discounted

Future Net Cash Flows From Proved Reserves” on page FS-75 for estimates of

proved reserve values for each of the three years ended December 31, 2012.

This Oil and Gas Reserves commentary should be read in conjunction with the

Properties, Plant and Equipment section of Note 1 to the Consolidated Financial

Statements, beginning on page FS-28, which includes a description of the

“successful efforts” method of accounting for oil and gas exploration and production

activities.

 Impairment of Properties, Plant and Equipment and Investments in

Affiliates The company assesses its properties, plant and equipment (PP&E) for

possible impairment whenever events or changes in circumstances indicate that the

carrying value of the assets may not be recoverable. Such indicators include changes

in the company’s business plans, changes in commodity prices and, for crude oil and

natural gas properties, significant downward revisions of estimated proved reserve

quantities. If the carrying value of an asset exceeds the future undiscounted cash

flows expected from the asset, an impairment charge is recorded for the excess of

carrying value of the asset over its estimated fair value.

 Determination as to whether and how much an asset is impaired involves

management estimates on highly uncertain matters, such as future commodity

prices, the effects of inflation and technology improvements on operating expenses,

production profiles, and the outlook for global or regional market supply-anddemand conditions for crude oil, natural gas, commodity chemicals and refined

products. However, the impairment reviews and calculations are based on

assumptions that are consistent with the company’s business plans and long-term

investment decisions. Refer also to the discussion of impairments of properties, plant

and equipment in Note 8 beginning on page FS-33 and to the section on Properties,

Plant and Equipment in Note 1, Summary of Significant Accounting Policies,

beginning on page FS-28.

 No material individual impairments of PP&E or Investments were recorded for

the three years ending December 31, 2012. A sensitivity analysis of the impact on

earnings for these periods if other assumptions had been used in impairment reviews

and impairment calculations is not practicable, given the broad range of the

company’s PP&E and the number of assumptions involved in the estimates. That is,

favorable changes to some assumptions might have avoided the need to impair any

assets in these periods, whereas unfavorable changes might have caused an additional

unknown number of other assets to become impaired.

 Investments in common stock of affiliates that are accounted for under the equity

method, as well as investments in other securities of these equity investees, are

reviewed for impairment when the fair value of the investment falls below the

company’s carrying value. When such a decline is deemed to be other than

temporary, an impairment charge is recorded to the income statement for the

difference between the investment’s carrying value and its estimated fair value at the

time.

FS-18
 In making the determination as to whether a decline is other than temporary, the

company considers such factors as the duration and extent of the decline, the

investee’s financial performance, and the company’s ability and intention to retain its

investment for a period that will be sufficient to allow for any anticipated recovery in

the investment’s market value. Differing assumptions could affect whether an

investment is impaired in any period or the amount of the impairment, and are not

subject to sensitivity analysis.

 From time to time, the company performs impairment reviews and determines

whether any write-down in the carrying value of an asset or asset group is required.

For example, when significant downward revisions to crude oil and natural gas

reserves are made for any single field or concession, an impairment review is

performed to determine if the carrying value of the asset remains recoverable. Also, if

the expectation of sale of a particular asset or asset group in any period has been

deemed more likely than not, an impairment review is performed, and if the estimated

net proceeds exceed the carrying value of the asset or asset group, no impairment

charge is required. Such calculations are reviewed each period until the asset or asset

group is disposed of. Assets that are not impaired on a held-and-used basis could

possibly become impaired if a decision is made to sell such assets. That is, the assets

would be impaired if they are classified as held-for-sale and the estimated proceeds

from the sale, less costs to sell, are less than the assets’ associated carrying values.

 Asset Retirement Obligations In the determination of fair value for an asset

retirement obligation (ARO), the company uses various assumptions and

judgments, including such factors as the existence of a legal obligation, estimated

amounts and timing of settlements, discount and inflation rates, and the expected

impact of advances in technology and process improvements. A sensitivity analysis of

the ARO impact on earnings for 2012 is not practicable, given the broad range of the

company's long-lived assets and the number of assumptions involved in the estimates.

That is, favorable changes to some assumptions would have reduced estimated

future obligations, thereby lowering accretion expense and amortization costs,

whereas unfavorable changes would have the opposite effect. Refer to Note 23 on

page FS-58 for additional discussions on asset retirement obligations.

 Contingent Losses Management also makes judgments and estimates in

recording liabilities for claims, litigation, tax matters and environmental remediation.

Actual costs can frequently vary from estimates for a variety of reasons. For

example, the costs for settlement of claims and litigation can vary from estimates

based on differing interpretations of laws, opinions on culpability and assessments on

the amount of damages. Similarly, liabilities for environmental remediation are subject

to change because of changes in laws, regulations and their interpretation, the

determination of additional information on the extent and nature of site contamination,

and improvements in technology.

 Under the accounting rules, a liability is generally recorded for these types of

contingencies if management determines the loss to be both probable and estimable.

The company generally reports these losses as “Operating expenses” or “Selling,

general and administrative expenses” on the Consolidated Statement of Income. An

exception to this handling is for income tax matters, for which benefits are recognized

only if management determines the tax position is “more likely than not” (i.e.,

likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For additional

discussion of income tax uncertainties, refer to Note 14 beginning on page FS-43.

Refer also to the business segment discussions elsewhere in this section for the effect

on earnings from losses associated with certain litigation, environmental remediation

and tax matters for the three years ended December 31, 2012.

 An estimate as to the sensitivity to earnings for these periods if other assumptions

had been used in recording these liabilities is not practicable because of the number of

contingencies that must be assessed, the number of underlying assumptions and the

wide range of reasonably possible outcomes, both in terms of the probability of loss

and the estimates of such loss.

New Accounting Standards

Refer to Note 17, on page FS-47 in the Notes to Consolidated Financial Statements,

for information regarding new accounting standards.

FS-19
Quarterly Results and Stock Market Data

Unaudited

2012 2011

Millions of dollars, except per-share amounts 4th Q 3rd Q 2nd Q 1st Q 4th Q 3rd Q 2nd Q 1st Q

Revenues and Other Income

 Sales and other operating revenues 1 $ 56,254 $ 55,660 $ 59,780 $ 58,896 $ 58,027 $ 61,261 $ 66,671 58,412

 Income from equity affiliates 1,815 1,274 2,091 1,709 1,567 2,227 1,882 $ 1,687

 Other income 2,483 1,110 737 100 391 944 395 242

Total Revenues and Other Income 60,552 58,044 62,608 60,705 59,985 64,432 68,948 60,341

Costs and Other Deductions

 Purchased crude oil and products 33,959 33,982 36,772 36,053 36,363 37,600 40,759 35,201

 Operating expenses 6,273 5,694 5,420 5,183 5,948 5,378 5,260 5,063

 Selling, general and administrative expenses 1,182 1,352 1,250 940 1,330 1,115 1,200 1,100

 Exploration expenses 357 475 493 403 386 240 422 168

 Depreciation, depletion and amortization 3,554 3,370 3,284 3,205 3,313 3,215 3,257 3,126

 Taxes other than on income1 3,251 3,239 3,034 2,852 2,680 3,544 4,843 4,561

 Interest and debt expense — — — — – – – –

Total Costs and Other Deductions 48,576 48,112 50,253 48,636 50,020 51,092 55,741 49,219

Income Before Income Tax Expense 11,976 9,932 12,355 12,069 9,965 13,340 13,207 11,122

Income Tax Expense 4,679 4,624 5,123 5,570 4,813 5,483 5,447 4,883

Net Income $ 7,297 $ 5,308 $ 7,232 $ 6,499 $ 5,152 $ 7,857 $ 7,760 $ 6,239

Less: Net income attributable to 

noncontrolling interests 52 55 22 28 29 28 28 28

Net Income Attributable to Chevron Corporation $ 7,245 $ 5,253 $ 7,210 $ 6,471 $ 5,123 $ 7,829 $ 7,732 $ 6,211

Per Share of Common Stock

 Net Income Attributable to Chevron Corporation

– Basic $ 3.73 $ 2.71 $ 3.68 $ 3.30 $ 2.61 $ 3.94 $ 3.88 $ 3.11

– Diluted $ 3.70 $ 2.69 $ 3.66 $ 3.27 $ 2.58 $ 3.92 $ 3.85 $ 3.09

Dividends $ 0.90 $ 0.90 $ 0.90 $ 0.81 $ 0.81 $ 0.78 $ 0.78 $ 0.72

Common Stock Price Range – High2 $ 118.38 $ 118.53 $ 108.79 $ 112.28 $ 110.01 $ 109.75 $ 109.94 $ 109.65

 – Low2 $ 100.66 $ 103.29 $ 95.73 $ 102.08 $ 86.68 $ 87.30 $ 97.00 $ 90.12

1

 Includes excise, value-added and similar taxes: $ 2,131 $ 2,163 $ 1,929 $ 1,787 $ 1,713 $ 1,974 $ 2,264 $ 2,134

2

 Intraday price.

The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 11, 2013, stockholders of record numbered approximately 168,000.

There are no restrictions on the company’s ability to pay dividends.

FS-20
Management’s Responsibility for Financial Statements

To the Stockholders of Chevron Corporation

Management of Chevron is responsible for preparing the accompanying consolidated financial statements and the related information appearing in this report.

The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions

and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgment.

 As stated in its report included herein, the independent registered public accounting firm of PricewaterhouseCoopers LLP has audited the company’s

consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).

 The Board of Directors of Chevron has an Audit Committee composed of directors who are not officers or employees of the company. The Audit

Committee meets regularly with members of management, the internal auditors and the independent registered public accounting firm to review accounting,

internal control, auditing and financial reporting matters. Both the internal auditors and the independent registered public accounting firm have free and direct

access to the Audit Committee without the presence of management.

Management’s Report on Internal Control Over Financial Reporting

The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in

Exchange Act Rule 13a-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the

effectiveness of the company’s internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of

Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the company’s management concluded that internal control

over financial reporting was effective as of December 31, 2012. 

 The effectiveness of the company’s internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP,

an independent registered public accounting firm, as stated in its report included herein.

John S. Watson Patricia E. Yarrington Matthew J. Foehr

Chairman of the Board Vice President Vice President

and Chief Executive Officer and Chief Financial Officer and Comptroller

February 22, 2013

FS-21
Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of Chevron Corporation: evidence supporting the amounts and disclosures in the financial statements,

assessing the accounting principles used and significant estimates made by

management, and evaluating the overall financial statement presentation. Our

audit of internal control over financial reporting included obtaining an

understanding of internal control over financial reporting, assessing the risk

that a material weakness exists, and testing and evaluating the design and

operating effectiveness of internal control based on the assessed risk. Our

audits also included performing such other procedures as we considered

necessary in the circumstances. We believe that our audits provide a

reasonable basis for our opinions.

 A company’s internal control over financial reporting is a process designed

to provide reasonable assurance regarding the reliability of financial reporting

and the preparation of financial statements for external purposes in accordance

with generally accepted accounting principles. A company’s internal control

over financial reporting includes those policies and procedures that (i) pertain

to the maintenance of records that, in reasonable detail, accurately and fairly

reflect the transactions and dispositions of the assets of the company;

(ii) provide reasonable assurance that transactions are recorded as necessary to

permit preparation of financial statements in accordance with generally

accepted accounting principles, and that receipts and expenditures of the

company are being made only in accordance with authorizations of

management and directors of the company; and (iii) provide reasonable

assurance regarding prevention or timely detection of unauthorized acquisition,

use, or disposition of the company’s assets that could have a material effect on

the financial statements.

 Because of its inherent limitations, internal control over financial reporting

may not prevent or detect misstatements. Also, projections of any evaluation of

effectiveness to future periods are subject to the risk that controls may become

inadequate because of changes in conditions, or that the degree of compliance

with the policies or procedures may deteriorate.

In our opinion, the accompanying consolidated balance sheet and the related

consolidated statements of income, comprehensive income, equity and of cash

flows present fairly, in all material respects, the financial position of Chevron

Corporation and its subsidiaries at December 31, 2012, and December 31,

2011, and the results of their operations and their cash flows for each of the

three years in the period ended December 31, 2012, in conformity with

accounting principles generally accepted in the United States of America. In

addition, in our opinion, the financial statement schedule listed in the index

appearing under Item 15(a)(2) presents fairly, in all material respects, the

information set forth therein when read in conjunction with the related

consolidated financial statements. Also in our opinion, the Company

maintained, in all material respects, effective internal control over financial

reporting as of December 31, 2012, based on criteria established in Internal

Control – Integrated Framework issued by the Committee of Sponsoring

Organizations of the Treadway Commission (COSO). The Company’s

management is responsible for these financial statements and financial

statement schedule, for maintaining effective internal control over financial

reporting, and for its assessment of the effectiveness of internal control over

financial reporting, included in the accompanying Management’s Report on

Internal Control Over Financial Reporting. Our responsibility is to express

opinions on these financial statements, on the financial statement schedule,

and on the Company’s internal control over financial reporting based on our

integrated audits. We conducted our audits in accordance with the standards of

the Public Company Accounting Oversight Board (United States). Those

standards require that we plan and perform the audits to obtain reasonable

assurance about whether the financial statements are free of material

misstatement and whether effective internal control over financial reporting was

maintained in all material respects. Our audits of the financial statements

included examining, on a test basis,

San Francisco, California

February 22, 2013

FS-22
Consolidated Statement of Income

Millions of dollars, except per-share amounts

Year ended December 31

2012 2011 2010

Revenues and Other Income

Sales and other operating revenues* $ 230,590 $ 244,371 $ 198,198

Income from equity affiliates 6,889 7,363 5,637

Other income 4,430 1,972 1,093

Total Revenues and Other Income 241,909 253,706 204,928

Costs and Other Deductions

Purchased crude oil and products 140,766 149,923 116,467

Operating expenses 22,570 21,649 19,188

Selling, general and administrative expenses 4,724 4,745 4,767

Exploration expenses 1,728 1,216 1,147

Depreciation, depletion and amortization 13,413 12,911 13,063

Taxes other than on income* 12,376 15,628 18,191

Interest and debt expense — — 50

Total Costs and Other Deductions 195,577 206,072 172,873

Income Before Income Tax Expense 46,332 47,634 32,055

Income Tax Expense 19,996 20,626 12,919

Net Income 26,336 27,008 19,136

Less: Net income attributable to noncontrolling interests 157 113 112

Net Income Attributable to Chevron Corporation $ 26,179 $ 26,895 $ 19,024

Per Share of Common Stock

Net Income Attributable to Chevron Corporation

– Basic $ 13.42 $ 13.54 $ 9.53

– Diluted $ 13.32 $ 13.44 $ 9.48

*Includes excise, value-added and similar taxes. $ 8,010 $ 8,085 $ 8,591

See accompanying Notes to the Consolidated Financial Statements.

FS-23
Consolidated Statement of Comprehensive Income

Millions of dollars

Year ended December 31

2012 2011 2010

Net Income $ 26,336 $ 27,008 $ 19,136

Currency translation adjustment

Unrealized net change arising during period 23 17 6

Unrealized holding gain (loss) on securities

Net gain (loss) arising during period 1 (11) (4)

Derivatives

Net derivatives gain on hedge transactions 20 20 25

Reclassification to net income of net realized (gain) loss (14) 9 5

Income taxes on derivatives transactions (3) (10) (10)

Total 3 19 20

Defined benefit plans

Actuarial loss

Amortization to net income of net actuarial loss 920 773 635

Actuarial loss arising during period (1,180) (3,250) (857)

Prior service cost

Amortization to net income of net prior service credits (61) (26) (61)

Prior service cost arising during period (142) (27) (12)

Defined benefit plans sponsored by equity affiliates (54) (81) (12)

Income taxes on defined benefit plans 143 1,030 140

Total (374) (1,581) (167)

Other Comprehensive Loss, Net of Tax (347) (1,556) (145)

Comprehensive Income 25,989 25,452 18,991

Comprehensive income attributable to noncontrolling interests (157) (113) (112)

Comprehensive Income Attributable to Chevron Corporation $ 25,832 $ 25,339 $ 18,879

See accompanying Notes to the Consolidated Financial Statements.

FS-24
Consolidated Balance Sheet

Millions of dollars, except per-share amounts

At December 31

2012 2011

Assets

Cash and cash equivalents $ 20,939 $ 15,864

Time deposits 708 3,958

Marketable securities 266 249

Accounts and notes receivable (less allowance: 2012 - $80; 2011 - $98) 20,997 21,793

Inventories:

Crude oil and petroleum products 3,923 3,420

Chemicals 475 502

Materials, supplies and other 1,746 1,621

Total inventories 6,144 5,543

Prepaid expenses and other current assets 6,666 5,827

Total Current Assets 55,720 53,234

Long-term receivables, net 3,053 2,233

Investments and advances 23,718 22,868

Properties, plant and equipment, at cost 263,481 233,432

Less: Accumulated depreciation, depletion and amortization 122,133 110,824

Properties, plant and equipment, net 141,348 122,608

Deferred charges and other assets 4,503 3,889

Goodwill 4,640 4,642

Total Assets $ 232,982 $ 209,474

Liabilities and Equity

Short-term debt $ 127 $ 340

Accounts payable 22,776 22,147

Accrued liabilities 5,738 5,287

Federal and other taxes on income 4,341 4,584

Other taxes payable 1,230 1,242

Total Current Liabilities 34,212 33,600

Long-term debt 11,966 9,684

Capital lease obligations 99 128

Deferred credits and other noncurrent obligations 21,502 19,181

Noncurrent deferred income taxes 17,672 15,544

Reserves for employee benefit plans 9,699 9,156

Total Liabilities 95,150 87,293

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

Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares 

issued at December 31, 2012 and 2011) 1,832 1,832

Capital in excess of par value 15,497 15,156

Retained earnings 159,730 140,399

Accumulated other comprehensive loss (6,369) (6,022)

Deferred compensation and benefit plan trust (282) (298)

Treasury stock, at cost (2012 - 495,978,691 shares; 2011 - 461,509,656 shares) (33,884) (29,685)

Total Chevron Corporation Stockholders' Equity 136,524 121,382

Noncontrolling interests 1,308 799

Total Equity 137,832 122,181

Total Liabilities and Equity $ 232,982 $ 209,474

See accompanying Notes to the Consolidated Financial Statements.

FS-25
Consolidated Statement of Cash Flows

Millions of dollars

Year ended December 31

2012 2011 2010

Operating Activities

Net Income $ 26,336 $ 27,008 $ 19,136

Adjustments

 Depreciation, depletion and amortization 13,413 12,911 13,063

 Dry hole expense 555 377 496

 Distributions less than income from equity affiliates (1,351) (570) (501)

 Net before-tax gains on asset retirements and sales (4,089) (1,495) (1,004)

 Net foreign currency effects 207 (103) 251

 Deferred income tax provision 2,015 1,589 559

 Net decrease in operating working capital 363 2,318 76

 Increase in long-term receivables (169) (150) (12)

 Decrease in other deferred charges 1,047 341 48

 Cash contributions to employee pension plans (1,228) (1,467) (1,450)

 Other 1,713 336 692

Net Cash Provided by Operating Activities 38,812 41,095 31,354

Investing Activities

Acquisition of Atlas Energy — (3,009) —

Advance to Atlas Energy — (403) —

Capital expenditures (30,938) (26,500) (19,612)

Proceeds and deposits related to asset sales 2,777 3,517 1,995

Net sales (purchases) of time deposits 3,250 (1,104) (2,855)

Net purchases of marketable securities (3) (74) (49)

Repayment of loans by equity affiliates 328 339 338

Net purchases of other short-term investments (210) (255) (732)

Net Cash Used for Investing Activities (24,796) (27,489) (20,915)

Financing Activities

Net borrowings (payments) of short-term obligations 264 23 (212)

Proceeds from issuances of long-term debt 4,007 377 1,250

Repayments of long-term debt and other financing obligations (2,224) (2,769) (156)

Cash dividends - common stock (6,844) (6,136) (5,669)

Distributions to noncontrolling interests (41) (71) (72)

Net purchases of treasury shares (4,142) (3,193) (306)

Net Cash Used for Financing Activities (8,980) (11,769) (5,165)

Effect of Exchange Rate Changes on Cash and Cash Equivalents 39 (33) 70

Net Change in Cash and Cash Equivalents 5,075 1,804 5,344

Cash and Cash Equivalents at January 1 15,864 14,060 8,716

Cash and Cash Equivalents at December 31 $ 20,939 $ 15,864 $ 14,060

See accompanying Notes to the Consolidated Financial Statements.

FS-26
Consolidated Statement of Equity

Shares in thousands; amounts in millions of dollars

2012 2011 2010

Shares Amount Shares Amount Shares Amount

Preferred Stock — $ — — $ — — $ —

Common Stock 2,442,677 $ 1,832 2,442,677 $ 1,832 2,442,677 $ 1,832

Capital in Excess of Par

Balance at January 1 $ 15,156 $ 14,796 $ 14,631

Treasury stock transactions 341 360 165

Balance at December 31 $ 15,497 $ 15,156 $ 14,796

Retained Earnings

Balance at January 1 $ 140,399 $ 119,641 $ 106,289

Net income attributable to Chevron Corporation 26,179 26,895 19,024

Cash dividends on common stock (6,844) (6,136) (5,669)

Stock dividends (3) (3) (5)

Tax (charge) benefit from dividends paid on 

unallocated ESOP shares and other (1) 2 2

 Balance at December 31 $ 159,730 $ 140,399 $ 119,641

Accumulated Other Comprehensive Loss

Currency translation adjustment

Balance at January 1 $ (88) $ (105) $ (111)

Change during year 23 17 6

Balance at December 31 $ (65) $ (88) $ (105)

Pension and other postretirement benefit plans

Balance at January 1 $ (6,056) $ (4,475) $ (4,308)

Change during year (374) (1,581) (167)

Balance at December 31 $ (6,430) $ (6,056) $ (4,475)

Unrealized net holding gain on securities

Balance at January 1 $ — $ 11 $ 15

Change during year 1 (11) (4)

Balance at December 31 $ 1 $ — $ 11

Net derivatives gain (loss) on hedge transactions

Balance at January 1 $ 122 $ 103 $ 83

Change during year 3 19 20

Balance at December 31 $ 125 $ 122 $ 103

Balance at December 31 $ (6,369) $ (6,022) $ (4,466)

Deferred Compensation and Benefit Plan Trust

Deferred Compensation

Balance at January 1 $ (58) $ (71) $ (109)

Net reduction of ESOP debt and other 16 13 38

Balance at December 31 $ (42) $ (58) $ (71)

Benefit Plan Trust (Common Stock) 14,168 (240) 14,168 (240) 14,168 (240)

Balance at December 31 14,168 $ (282) 14,168 $ (298) 14,168 $ (311)

Treasury Stock at Cost

Balance at January 1 461,510 $ (29,685) 435,196 $ (26,411) 434,955 $ (26,168)

Purchases 46,669 (5,004) 42,424 (4,262) 9,091 (775)

Issuances - mainly employee benefit plans (12,200) 805 (16,110) 988 (8,850) 532

Balance at December 31 495,979 $ (33,884) 461,510 $ (29,685) 435,196 $ (26,411)

Total Chevron Corporation Stockholders' Equity

at December 31 $ 136,524 $ 121,382 $ 105,081

Noncontrolling Interests $ 1,308 $ 799 $ 730

Total Equity $ 137,832 $ 122,181 $ 105,811

See accompanying Notes to the Consolidated Financial Statements.

FS-27
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 1

Summary of Significant Accounting Policies

General 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 gasto-liquids project. Downstream operations relate primarily to refining crude

oil into petroleum products; marketing of crude oil and refined products;

transporting 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 additives for

fuels and lubricant oils.

 The company’s Consolidated Financial Statements are prepared in

accordance with accounting principles generally accepted in the United

States of America. These require the use of estimates and assumptions that

affect the assets, liabilities, revenues and expenses reported in the financial

statements, as well as amounts included in the notes thereto, including

discussion and disclosure of contingent liabilities. Although the company

uses its best estimates and judgments, actual results could differ from these

estimates as future confirming events occur.

Subsidiary and Affiliated Companies The Consolidated Financial

Statements include the accounts of controlled subsidiary companies more

than 50 percent-owned and any variable-interest entities in which the

company is the primary beneficiary. Undivided interests in oil and gas joint

ventures and certain other assets are consolidated on a proportionate basis.

Investments in and advances to affiliates in which the company has a

substantial ownership interest of approximately 20 percent to 50 percent, or

for which the company exercises significant influence but not control over

policy decisions, are accounted for by the equity method. As part of that

accounting, the company recognizes gains and losses that arise from the

issuance of stock by an affiliate that results in changes in the company’s

proportionate share of the dollar amount of the affiliate’s equity currently in

income.

 Investments are assessed for possible impairment when events indicate

that the fair value of the investment may be below the company’s carrying

value. When such a condition is deemed to be other than temporary, the

carrying value of the investment is written down to its fair value, and the

amount of the write-down is included in net income. In making the

determination as to whether a decline is other than temporary, the company

considers such factors as the duration and extent of the decline, the

investee’s financial performance, and the company’s ability and intention to

retain its investment for a period that will be sufficient to

allow for any anticipated recovery in the investment’s market value. The

new cost basis of investments in these equity investees is not changed for

subsequent recoveries in fair value.

 Differences between the company’s carrying value of an equity

investment and its underlying equity in the net assets of the affiliate are

assigned to the extent practicable to specific assets and liabilities based on

the company’s analysis of the various factors giving rise to the difference.

When appropriate, the company’s share of the affiliate’s reported earnings

is adjusted quarterly to reflect the difference between these allocated values

and the affiliate’s historical book values.

Derivatives The majority of the company’s activity in derivative

commodity instruments is intended to manage the financial risk posed by

physical transactions. For some of this derivative activity, generally limited

to large, discrete or infrequently occurring transactions, the company may

elect to apply fair value or cash flow hedge accounting. For other similar

derivative instruments, generally because of the short-term nature of the

contracts or their limited use, the company does not apply hedge

accounting, and changes in the fair value of those contracts are reflected in

current income. For the company’s commodity trading activity, gains and

losses from derivative instruments are reported in current income. The

company may enter into interest rate swaps from time to time as part of its

overall strategy to manage the interest rate risk on its debt. Interest rate

swaps related to a portion of the company’s fixed-rate debt, if any, may be

accounted for as fair value hedges. Interest rate swaps related to floating-rate

debt, if any, are recorded at fair value on the balance sheet with resulting

gains and losses reflected in income. Where Chevron is a party to master

netting arrangements, fair value receivable and payable amounts recognized

for derivative instruments executed with the same counterparty are generally

offset on the balance sheet.

Short-Term Investments All short-term investments are classified as

available for sale and are in highly liquid debt securities. Those investments

that are part of the company’s cash management portfolio and have original

maturities of three months or less are reported as “Cash equivalents.” Bank

time deposits with maturities greater than 90 days are reported as “Time

deposits.” The balance of short-term investments is reported as “Marketable

securities” and is marked-to-market, with any unrealized gains or losses

included in “Other comprehensive income.”

Inventories Crude oil, petroleum products and chemicals inventories are

generally stated at cost, using a last-in, first-out method. In the aggregate,

these costs are below market. “Materials, supplies and other” inventories

generally are stated at average cost.

FS-28
 Note 1 Summary of Significant Accounting Policies - Continued

Properties, Plant and Equipment The successful efforts method is used

for crude oil and natural gas exploration and production activities. All costs

for development wells, related plant and equipment, proved mineral

interests in crude oil and natural gas properties, and related asset retirement

obligation (ARO) assets are capitalized. Costs of exploratory wells are

capitalized pending determination of whether the wells found proved

reserves. Costs of wells that are assigned proved reserves remain

capitalized. Costs also are capitalized for exploratory wells that have found

crude oil and natural gas reserves even if the reserves cannot be classified as

proved when the drilling is completed, provided the exploratory well has

found a sufficient quantity of reserves to justify its completion as a

producing well and the company is making sufficient progress assessing

the reserves and the economic and operating viability of the project. All other

exploratory wells and costs are expensed. Refer to Note 18, beginning on

page FS-47, for additional discussion of accounting for suspended

exploratory well costs.

 Long-lived assets to be held and used, including proved crude oil and

natural gas properties, are assessed for possible impairment by comparing

their carrying values with their associated undiscounted, future net beforetax cash flows. Events that can trigger assessments for possible

impairments include write-downs of proved reserves based on field

performance, significant decreases in the market value of an asset,

significant change in the extent or manner of use of or a physical change in

an asset, and a more-likely-than-not expectation that a long-lived asset or

asset group will be sold or otherwise disposed of significantly sooner than

the end of its previously estimated useful life. Impaired assets are written

down to their estimated fair values, generally their discounted, future net

before-tax cash flows. For proved crude oil and natural gas properties in the

United States, the company generally performs an impairment review on an

individual field basis. Outside the United States, reviews are performed on

a country, concession, development area or field basis, as appropriate. In

Downstream, impairment reviews are performed on the basis of a refinery, a

plant, a marketing/lubricants area or distribution area, as appropriate.

Impairment amounts are recorded as incremental “Depreciation, depletion

and amortization” expense.

 Long-lived assets that are held for sale are evaluated for possible

impairment by comparing the carrying value of the asset with its fair value

less the cost to sell. If the net book value exceeds the fair value less cost to

sell, the asset is considered impaired and adjusted to the lower value. Refer

to Note 8, beginning on page FS-33, relating to fair value measurements.

 The fair value of a liability for an ARO is recorded as an asset and a

liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be

reasonably estimated. Refer also to Note 23, on page FS-58, relating to

AROs.

 Depreciation and depletion of all capitalized costs of proved crude oil

and natural gas producing properties, except mineral interests, are expensed

using the unit-of-production method, generally by individual field, as the

proved developed reserves are produced. Depletion expenses for capitalized

costs of proved mineral interests are recognized using the unit-of-production

method by individual field as the related proved reserves are produced.

Periodic valuation provisions for impairment of capitalized costs of

unproved mineral interests are expensed.

 The capitalized costs of all other plant and equipment are depreciated or

amortized over their estimated useful lives. In general, the declining-balance

method is used to depreciate plant and equipment in the United States; the

straight-line method is generally used to depreciate international plant and

equipment and to amortize all capitalized leased assets.

 Gains or losses are not recognized for normal retirements of properties,

plant and equipment subject to composite group amortization or

depreciation. Gains or losses from abnormal retirements are recorded as

expenses, and from sales as “Other income.”

 Expenditures for maintenance (including those for planned major

maintenance projects), repairs and minor renewals to maintain facilities in

operating condition are generally expensed as incurred. Major replacements

and renewals are capitalized.

Goodwill Goodwill resulting from a business combination is not subject to

amortization. As required by accounting standards for goodwill (ASC 350),

the company tests such goodwill at the reporting unit level for impairment

on an annual basis and between annual tests if an event occurs or

circumstances change that would more likely than not reduce the fair value

of the reporting unit below its carrying amount.

Environmental Expenditures Environmental expenditures that relate to

ongoing operations or to conditions caused by past operations are expensed.

Expenditures that create future benefits or contribute to future revenue

generation are capitalized.

 Liabilities related to future remediation costs are recorded when

environmental assessments or cleanups or both are probable and the costs

can be reasonably estimated. For the company’s U.S. and Canadian

marketing facilities, the accrual is based in part on the probability that a

future remediation commitment will be required. For crude oil, natural gas

and

FS-29
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 1 Summary of Significant Accounting Policies - Continued

mineral-producing properties, a liability for an ARO is made in accordance

with accounting standards for asset retirement and environmental

obligations. Refer to Note 23, on page FS-58, for a discussion of the

company’s AROs.

 For federal Superfund sites and analogous sites under state laws, the

company records a liability for its designated share of the probable and

estimable costs, and probable amounts for other potentially responsible

parties when mandated by the regulatory agencies because the other parties

are not able to pay their respective shares.

 The gross amount of environmental liabilities is based on the company’s

best estimate of future costs using currently available technology and

applying current regulations and the company’s own internal environmental

policies. Future amounts are not discounted. Recoveries or reimbursements

are recorded as assets when receipt is reasonably assured.

Currency Translation The U.S. dollar is the functional currency for

substantially all of the company’s consolidated operations and those of its

equity affiliates. For those operations, all gains and losses from currency

remeasurement are included in current period income. The cumulative

translation effects for those few entities, both consolidated and affiliated,

using functional currencies other than the U.S. dollar are included in

“Currency translation adjustment” on the Consolidated Statement of Equity.

Revenue Recognition Revenues associated with sales of crude oil, natural

gas, coal, petroleum and chemicals products, and all other sources are

recorded when title passes to the customer, net of royalties, discounts and

allowances, as applicable. Revenues from natural gas production from

properties in which Chevron has an interest with other producers are

generally recognized using the entitlement method. Excise, value-added and

similar taxes assessed by a governmental authority on a revenue-producing

transaction between a seller and a customer are presented on a gross basis.

The associated amounts are shown as a footnote to the Consolidated

Statement of Income, on page FS-23. Purchases and sales of inventory with

the same counterparty that are entered into in contemplation of one another

(including buy/sell arrangements) are combined and recorded on a net basis

and reported in “Purchased crude oil and products” on the Consolidated

Statement of Income.

Stock Options and Other Share-Based Compensation The company

issues stock options and other share-based compensation to its employees

and accounts for these transactions under the accounting standards for

share-based compensation (ASC 718). For equity awards, such as stock

options, total compensation cost is based on the grant date fair value, and

for liability awards, such as stock appreciation rights, total compensation

cost is based on the settlement value. The company recognizes stock-based

compensation expense for all awards over the service period required to earn

the award, which is the shorter of the vesting period or the time period an

employee becomes eligible to retain the award at retirement. Stock options

and stock appreciation rights granted under the company’s Long-Term

Incentive Plan have graded vesting provisions by which one-third of each

award vests on the first, second and third anniversaries of the date of grant.

The company amortizes these graded awards on a straight-line basis.

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. The term “earnings” is

defined as “Net Income Attributable to Chevron Corporation.”

 Activity for the equity attributable to noncontrolling interests for 2012,

2011 and 2010 is as follows:

2012 2011 2010

Balance at January 1 $ 799 $ 730 $ 647

Net income 157 113 112

Distributions to noncontrolling interests (41) (71) (72)

Other changes, net* 393 27 43

Balance at December 31 $ 1,308 $ 799 $ 730

* Includes components of comprehensive income, which are disclosed separately in the

Consolidated Statement of Comprehensive Income.

FS-30
Note 3

Information Relating to the Consolidated Statement of Cash Flows

Year ended December 31

2012 2011 2010

Net decrease (increase) in operating

working capital was composed of the

following:

Decrease (increase) in accounts and 

notes receivable $ 1,153 $ (2,156) $ (2,767)

(Increase) decrease in inventories (233) (404) 15

Increase in prepaid expenses and other

current assets (471) (853) (542)

Increase in accounts payable and accrued

liabilities 544 3,839 3,049

(Decrease) increase in income and other

taxes payable (630) 1,892 321

Net decrease in operating working capital $ 363 $ 2,318 $ 76

Net cash provided by operating activities

includes the following cash payments

for interest and income taxes:

Interest paid on debt 

(net of capitalized interest) $ — $ — $ 34

Income taxes $ 17,334 $ 17,374 $ 11,749

Net sales of marketable securities

consisted of the following gross

amounts:

Marketable securities purchased $ (35) $ (112) $ (90)

Marketable securities sold 32 38 41

Net purchases of marketable securities $ (3) $ (74) $ (49)

Net sales (purchases) of time deposits

consisted of the following gross

amounts:

Time deposits purchased $ (717) $ (6,439) $ (5,060)

Time deposits matured 3,967 5,335 2,205

Net sales (purchases) of time deposits $ 3,250 $ (1,104) $ (2,855)

In accordance with accounting standards for cash-flow classifications for stock options

(ASC 718), the “Net decrease in operating working capital ” includes reductions of

$98, $121 and $67 for excess income tax benefits associated with stock options

exercised during 2012, 2011 and 2010, respectively. These amounts are offset by an

equal amount in “Net purchases of treasury shares.” "Other" includes changes in

postretirement benefits obligations and other long-term liabilities.

 The “Acquisition of Atlas Energy” reflects the $3,009 of cash paid for all the

common shares of Atlas in February 2011. An “Advance to Atlas Energy” of $403

was made to facilitate the purchase of a 49 percent interest in Laurel Mountain

Midstream LLC on the day of closing. The “Net decrease (increase) in operating

working capital” includes $184 for payments made in connection with Atlas equity

awards subsequent to the acquisition. Refer to Note 26, beginning on page FS-60

for additional discussion of the Atlas acquisition.

 The “Repayments of long-term debt and other financing obligations” in 2011

includes $761 for repayment of Atlas debt and $271 for payoff of the Atlas revolving

credit facility.

 The “Net purchases of treasury shares” represents the cost of common shares

acquired less the cost of shares issued for share-based compensation plans. Purchases

totaled $5,004, $4,262 and $775 in 2012, 2011 and 2010, respectively. In 2012

and 2011, the company purchased 46.6 million and 42.3 million common shares for

$5,000 and $4,250 under its ongoing share repurchase program, respectively.

 In 2012 and 2011, “Net purchases of other short-term investments ” consist of

restricted cash associated with tax payments, upstream abandonment activities, funds

held in escrow for an asset acquisition and capital investment projects that was

invested in short-term securities and reclassified from “Cash and cash equivalents” to

“Deferred charges and other assets” on the Consolidated Balance Sheet. The

company issued $374 and $1,250 in 2011 and 2010, respectively, of tax exempt

bonds as a source of funds for U.S. refinery projects, which is included in

“Proceeds from issuance of long-term debt.”

 The Consolidated Statement of Cash Flows excludes changes to the Consolidated

Balance Sheet that did not affect cash. The 2012 period excludes the effects of $800

of proceeds to be received in future periods for the sale of an equity interest in the

Wheatstone Project. "Capital expenditures" in the 2012 period excludes a $1,850

increase in "Properties, plant and equipment" related to an upstream asset exchange

in Australia. Refer also to Note 23, on page FS-58, for a discussion of revisions to

the company’s AROs that also did not involve cash receipts or payments for the three

years ending December 31, 2012.

FS-31
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 3 Information Relating to the Consolidated Statement of Cash Flows - Continued

 The major components of “Capital expenditures” and the reconciliation of this

amount to the reported capital and exploratory expenditures, including equity

affiliates, are presented in the following table:

Year ended December 31

2012 2011 2010

Additions to properties, plant 

and equipment * $ 29,526 $ 25,440 $ 18,474

Additions to investments 1,042 900 861

Current-year dry hole expenditures 475 332 414

Payments for other liabilities 

and assets, net (105) (172) (137)

Capital expenditures 30,938 26,500 19,612

Expensed exploration expenditures 1,173 839 651

Assets acquired through capital lease

obligations and other financing

obligations 1 32 104

Capital and exploratory expenditures,

excluding equity affiliates 32,112 27,371 20,367

Company's share of expenditures by

equity affiliates 2,117 1,695 1,388

Capital and exploratory expenditures,

including equity affiliates $ 34,229 $ 29,066 $ 21,755

* Excludes noncash additions of $4,569 in 2012, $945 in 2011 and $2,753 in 2010.

Note 4

Summarized Financial Data – Chevron U.S.A. Inc.

Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation.

CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses.

Assets include those related to the exploration and production of crude oil, natural

gas and natural gas liquids and those associated with the refining, marketing, supply

and distribution of products derived from petroleum, excluding most of the

regulated pipeline operations of Chevron. CUSA also holds the company’s

investment in the Chevron Phillips Chemical Company LLC joint venture, which is

accounted for using the equity method.

During 2012, Chevron implemented legal reorganizations in which certain Chevron

subsidiaries transferred assets to or under CUSA. The summarized financial

information for CUSA and its consolidated subsidiaries presented in the table below

gives retroactive effect to the reorganizations as if they had occurred on January 1,

2010. However, the financial information in the following table may not reflect the

financial position and operating results in the periods presented if the reorganization

had occurred on that date.

 The summarized financial information for CUSA and its consolidated subsidiaries

is as follows:

Year ended December 31

2012 2011 2010

Sales and other operating revenues $ 183,215 $ 187,929 $ 143,352

Total costs and other deductions 175,009 178,510 137,964

Net income attributable to CUSA 6,216 6,898 4,154

At December 31

2012 2011

Current assets $ 18,983 $ 34,490

Other assets 52,082 47,556

Current liabilities 18,161 19,081

Other liabilities 26,472 26,160

Total CUSA net equity 26,432 36,805

—

Memo: Total debt $ 14,482 $ 14,763

Note 5

Summarized Financial Data – Chevron Transport Corporation Ltd.

Chevron Transport Corporation Ltd. (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 from 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:

Year ended December 31

2012 2011 2010

Sales and other operating revenues $ 606 $ 793 $ 885

Total costs and other deductions 745 974 1,008

Net loss attributable to CTC (135) (177) (116)

At December 31

2012 2011

Current assets $ 199 $ 290

Other assets 313 228

Current liabilities 154 114

Other liabilities 415 346

Total CTC net (deficit) equity (57) 58

There were no restrictions on CTC's ability to pay dividends or make loans or

advances at December 31, 2012.

FS-32
Note 6

Summarized Financial Data – Tengizchevroil LLP

Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO).

Refer to Note 11, on page FS-38, for a discussion of TCO operations.

 Summarized financial information for 100 percent of TCO is presented in the

following table:

Year ended December 31

2012 2011 2010

Sales and other operating revenues $ 23,089 $ 25,278 $ 17,812

Costs and other deductions 10,064 10,941 8,394

Net income attributable to TCO 9,119 10,039 6,593

At December 31

2012 2011

Current assets $ 3,251 $ 3,477

Other assets 12,020 11,619

Current liabilities 2,597 2,995

Other liabilities 3,390 3,759

Total TCO net equity $ 9,284 $ 8,342

Note 7

Lease Commitments

Certain noncancelable leases are classified as capital leases, and the leased assets are

included as part of “Properties, plant and equipment, at cost” on the Consolidated

Balance Sheet. Such leasing arrangements involve crude oil production and

processing equipment, service stations, bareboat charters, office buildings, and other

facilities. Other leases are classified as operating leases and are not capitalized. The

payments on operating leases are recorded as expense. Details of the capitalized leased

assets are as follows:

At December 31

2012 2011

Upstream $ 433 $ 585

Downstream 316 316

All Other — —

Total 749 901

Less: Accumulated amortization 479 568

Net capitalized leased assets $ 270 $ 333

 Rental expenses incurred for operating leases during 2012, 2011 and 2010 were

as follows:

Year ended December 31

2012 2011 2010

Minimum rentals $ 973 $ 892 $ 931

Contingent rentals 7 11 10

Total 980 903 941

Less: Sublease rental income 32 39 41

Net rental expense $ 948 $ 864 $ 900

 Contingent rentals are based on factors other than the passage of time,

principally sales volumes at leased service stations. Certain leases include

escalation clauses for adjusting rentals to reflect changes in price indices, renewal

options ranging up to 25 years, and options to purchase the leased property during

or at the end of the initial or renewal lease period for the fair market value or other

specified amount at that time.

 At December 31, 2012, the estimated future minimum lease payments (net of

noncancelable sublease rentals) under operating and capital leases, which at inception

had a noncancelable term of more than one year, were as follows:

At December 31

Operating Capital

Leases Leases

Year: 2013 $ 727 $ 45

2014 657 37

2015 618 23

2016 528 13

2017 401 12

 Thereafter 617 59

Total $ 3,548 $ 189

Less: Amounts representing interest and

executory costs $ (40)

Net present values 149

Less: Capital lease obligations 

included in short-term debt (50)

Long-term capital lease obligations $ 99

Note 8

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.

FS-33
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 8 Fair Value Measurements - Continued

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.

The table below shows the fair value hierarchy for assets and liabilities measured at

fair value on a recurring basis at December 31, 2012, and December 31, 2011.

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

December 31, 2012.

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 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.

Properties, plant and equipment The company did not have any material longlived assets measured at fair value on a nonrecurring basis to report in 2012 or 2011.

Investments and advances The company did not have any material investments

and advances measured at fair value on a nonrecurring basis to report in 2012 or

2011.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

At December 31, 2012 At December 31, 2011

Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3

Marketable securities $ 266 $ 266 $ — $ — $ 249 $ 249 $ — $ —

Derivatives 86 21 65 — 208 104 104 —

Total Assets at Fair Value $ 352 $ 287 $ 65 $ — $ 457 $ 353 $ 104 $ —

Derivatives 149 148 1 — 102 101 1 —

Total Liabilities at Fair Value $ 149 $ 148 $ 1 $ — $ 102 $ 101 $ 1 $ —

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

At December 31 At December 31

Before-Tax Loss Before-Tax Loss

Total Level 1 Level 2 Level 3 Year 2012 Total Level 1 Level 2 Level 3 Year 2011

Properties, plant and

 equipment, net (held and used) $ 84 $ — $ — $ 84 $ 213 $ 67 $ — $ — $ 67 $ 81

Properties, plant and 

equipment, net (held for sale) 16 — — 16 17 167 — 167 — 54

Investments and advances — — — — 15 — — — — 108

Total Nonrecurring Assets

 at Fair Value $ 100 $ — $ — $ 100 $ 245 $ 234 $ — $ 167 $ 67 $ 243

FS-34
 Note 8 Fair Value Measurements - Continued

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 $20,939 and $15,864 at December 31,

2012, and December 31, 2011, respectively. The instruments held in “Time

deposits” are bank time deposits with maturities greater than 90 days, and had

carrying/fair values of $708 and $3,958 at December 31, 2012, and December 31,

2011, respectively. The fair values of cash, cash equivalents and bank time deposits

are classified as Level 1 and reflect the cash that would have been received if the

instruments were settled at December 31, 2012.

"Cash and cash equivalents” do not include investments with a carrying/fair value of

$1,454 and $1,240 at December 31, 2012, and December 31, 2011, respectively.

At December 31, 2012, these investments are classified as Level 1 and include

restricted funds related to tax payments, upstream abandonment activities, funds

held in escrow for an asset acquisition and capital investment projects, all of which are

reported in “Deferred charges and other assets” on the Consolidated Balance Sheet.

Long-term debt of $6,086 and $4,101 at December 31, 2012, and December 31,

2011, had estimated fair values of $6,770 and $4,928, respectively. Long-term debt

primarily includes corporate issued bonds. The fair value of corporate bonds is

$5,853 and classified as Level 1. The fair value of the other bonds is $917 and

classified as Level 2.

 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 December 31, 2012 and 2011, were not material.

The table on previous page shows the fair value hierarchy for assets and liabilities

measured at fair value on a nonrecurring basis at December 31, 2012 and 2011.

Note 9

Financial and Derivative Instruments

Derivative Commodity Instruments Chevron is exposed to market risks related

to price volatility of crude oil, refined products, natural gas, natural gas liquids,

liquefied natural gas and refinery feedstocks.

 The company uses derivative commodity instruments to manage these exposures

on a portion of its activity, including firm commitments and anticipated transactions

for the purchase, sale and storage of crude oil, refined products, natural gas, natural

gas liquids and feedstock for company refineries. From time to time, the company

also uses derivative commodity instruments for limited trading purposes.

 The company’s derivative commodity 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 commodity derivative activities.

 The company uses International Swaps and Derivatives Association agreements to

govern derivative contracts with certain counterparties to mitigate credit risk.

Depending on the nature of the derivative transactions, bilateral collateral

arrangements may also be required. When the company is engaged in more than one

outstanding derivative transaction with the same counterparty and also has a legally

enforceable netting agreement with that counterparty, the net mark-to-market

exposure represents the netting of the positive and negative exposures with that

counterparty and is a reasonable measure of the company’s credit risk exposure. The

company also uses other netting agreements with certain counterparties with which it

conducts significant transactions to mitigate credit risk.

 Derivative instruments measured at fair value at December 31, 2012,

December 31, 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

Type of Balance Sheet At December 31 At December 31

Contract Classification 2012 2011

Commodity Accounts and notes receivable,

net $ 57 $ 133

Commodity Long-term receivables, net 29 75

Total Assets at Fair Value $ 86 $ 208

Commodity Accounts payable $ 112 $ 36

Commodity Deferred credits and other

noncurrent obligations 37 66

Total Liabilities at Fair Value $ 149 $ 102

Consolidated Statement of Income: The Effect of Derivatives Not

Designated as Hedging Instruments

Gain/(Loss)

Type of Derivative Statement of Year ended December 31

Contract Income Classification 2012 2011 2010

Commodity Sales and other 

operating revenues $ (49) $ (255) $ (98)

Commodity Purchased crude oil 

and products (24) 15 (36)

Commodity Other income 6 (2) (1)

$ (67) $ (242) $ (135)

FS-35
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 9 Financial and Derivative Instruments - Continued

Concentrations of Credit Risk The company’s financial instruments that are

exposed to concentrations of credit risk consist primarily of its cash equivalents, time

deposits, marketable securities, derivative financial instruments and trade receivables.

The company’s short-term investments are placed with a wide array of financial

institutions with high credit ratings. Company investment policies limit the company’s

exposure both to credit risk and to concentrations of credit risk. Similar policies on

diversification and creditworthiness are applied to the company’s counterparties in

derivative instruments.

 The trade receivable balances, reflecting the company’s diversified sources of

revenue, are dispersed among the company’s broad customer base worldwide. As a

result, the company believes concentrations of credit risk are limited. The company

routinely assesses the financial strength of its customers. When the financial strength

of a customer is not considered sufficient, alternative risk mitigation measures may

be deployed including requiring pre-payments, letters of credit or other acceptable

collateral instruments to support sales to customers.

Note 10

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, 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.

FS-36
 Note 10 Operating Segments and Geographic Data - Continued

 Segment managers for the reportable segments are directly accountable to and

maintain regular contact with the company’s CODM to discuss the segment’s

operating activities and financial performance. The CODM approves annual capital and

exploratory budgets at the reportable segment level, as well as reviews capital and

exploratory funding for major projects and approves major changes to the annual

capital and exploratory budgets. However, business-unit managers within the

operating segments are directly responsible for decisions relating to project

implementation and all other matters connected with daily operations. Company

officers who are members of the 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).

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 are presented in the following table:

Year ended December 31

2012 2011 2010

Segment Earnings

Upstream

 United States $ 5,332 $ 6,512 $ 4,122

 International 18,456 18,274 13,555

Total Upstream 23,788 24,786 17,677

Downstream

 United States 2,048 1,506 1,339

 International 2,251 2,085 1,139

Total Downstream 4,299 3,591 2,478

Total Segment Earnings 28,087 28,377 20,155

All Other

 Interest expense — — (41)

 Interest income 83 78 70

 Other (1,991) (1,560) (1,160)

Net Income Attributable 

to Chevron Corporation $ 26,179 $ 26,895 $ 19,024

Segment Assets Segment assets do not include intercompany investments or

intercompany receivables. Segment assets at year-end 2012 and 2011 are as follows:

At December 31

2012 2011

Upstream

 United States $ 41,891 $ 37,108

 International 115,806 98,540

 Goodwill 4,640 4,642

Total Upstream 162,337 140,290

Downstream

 United States 23,023 22,182

 International 20,024 20,517

Total Downstream 43,047 42,699

Total Segment Assets 205,384 182,989

All Other*

 United States 7,727 8,824

 International 19,871 17,661

Total All Other 27,598 26,485

Total Assets – United States 72,641 68,114

Total Assets – International 155,701 136,718

Goodwill 4,640 4,642

Total Assets $ 232,982 $ 209,474

* “All Other” assets consist primarily of worldwide cash, cash equivalents, time deposits and marketable

securities, real estate, energy services, information systems, mining operations, power generation businesses,

alternative fuels, technology companies, and assets of the corporate administrative functions.

Segment Sales and Other Operating Revenues Operating segment sales and

other operating revenues, including internal transfers, for the years 2012, 2011 and

2010, are presented in the table that follows. 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 additives for fuels and lubricant

oils and the transportation and trading of refined products, crude oil and natural gas

liquids. “All Other” activities include revenues from mining operations, power

generation businesses, insurance operations, real estate activities, energy services,

alternative fuels, and technology companies.

FS-37
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 10 Operating Segments and Geographic Data - Continued
Year ended December 31

2012 2011 2010

Upstream

 United States $ 6,416 $ 9,623 $ 10,316

 Intersegment 17,229 18,115 13,839

 Total United States 23,645 27,738 24,155

 International 19,459 20,086 17,300

 Intersegment 34,094 35,012 23,834

 Total International 53,553 55,098 41,134

Total Upstream 77,198 82,836 65,289

Downstream

 United States 83,043 86,793 70,436

 Excise and similar taxes 4,665 4,199 4,484

 Intersegment 49 86 115

 Total United States 87,757 91,078 75,035

 International 113,279 119,254 90,922

 Excise and similar taxes 3,346 3,886 4,107

 Intersegment 80 81 93

 Total International 116,705 123,221 95,122

Total Downstream 204,462 214,299 170,157

All Other

 United States 378 526 610

 Intersegment 1,300 1,072 947

 Total United States 1,678 1,598 1,557

 International 4 4 23

 Intersegment 48 42 39

 Total International 52 46 62

Total All Other 1,730 1,644 1,619

Segment Sales and Other 

Operating Revenues

 United States 113,080 120,414 100,747

 International 170,310 178,365 136,318

Total Segment Sales and Other 

Operating Revenues 283,390 298,779 237,065

Elimination of intersegment sales (52,800) (54,408) (38,867)

Total Sales and Other 

Operating Revenues $ 230,590 $ 244,371 $ 198,198

Segment Income Taxes Segment income tax expense for the years 2012, 2011

and 2010 is as follows:

Year ended December 31

2012 2011 2010

Upstream

 United States $ 2,820 $ 3,701 $ 2,285

 International 16,554 16,743 10,480

Total Upstream 19,374 20,444 12,765

Downstream

 United States 1,051 785 680

 International 587 416 462

Total Downstream 1,638 1,201 1,142

All Other (1,016) (1,019) (988)

Total Income Tax Expense $ 19,996 $ 20,626 $ 12,919

Other Segment Information Additional information for the segmentation of

major equity affiliates is contained in Note 11 below. Information related to

properties, plant and equipment by segment is contained in Note 12, on page FS-40.

Note 11

Investments and Advances

Equity in earnings, together with investments in and advances to companies

accounted for using the equity method and other investments accounted for at or

below cost, is shown in the following table. For certain equity affiliates, Chevron pays

its share of some income taxes directly. For such affiliates, the equity in earnings does

not include these taxes, which are reported on the Consolidated Statement of Income

as “Income tax expense.”

Investments and Advances Equity in Earnings

At December 31 Year ended December 31

2012 2011 2012 2011 2010

Upstream

Tengizchevroil $ 5,451 $ 5,306 $ 4,614 $ 5,097 $ 3,398

Petropiar 952 909 55 116 262

Caspian Pipeline

Consortium 1,187 1,094 96 122 124

Petroboscan 1,261 1,032 229 247 222

Angola LNG

Limited 3,186 2,921 (106) (42) (21)

Other 2,658 2,420 266 166 319

Total Upstream 14,695 13,682 5,154 5,706 4,304

Downstream

GS Caltex

Corporation 2,610 2,572 249 248 158

Chevron Phillips

Chemical

Company LLC 3,451 2,909 1,206 985 704

Star Petroleum

Refining Company

Ltd. — 1,022 22 75 122

Caltex Australia

Ltd. 835 819 77 117 101

Colonial Pipeline

Company — — — — 43

Other 837 630 196 183 151

Total Downstream 7,733 7,952 1,750 1,608 1,279

All Other

Other 640 516 (15) 49 54

Total equity

method $ 23,068 $ 22,150 $ 6,889 $ 7,363 $ 5,637

Other at or below

cost 650 718

Total investments

and advances $ 23,718 $ 22,868

Total United States $ 5,788 $ 4,847 $ 1,268 $ 1,119 $ 846

Total International $ 17,930 $ 18,021 $ 5,621 $ 6,244 $ 4,791

 Descriptions of major affiliates, including significant differences between the

company’s carrying value of its investments and its underlying equity in the net

assets of the affiliates, are as follows:

Tengizchevroil Chevron has a 50 percent equity ownership interest in

Tengizchevroil (TCO), which was formed in 1993 to develop the Tengiz and Korolev

crude oil fields in KazakhFS-38
 Note 11 Investments and Advances - Continued

stan over a 40-year period. At December 31, 2012, the company’s carrying value of

its investment in TCO was about $170 higher than the amount of underlying equity

in TCO’s net assets. This difference results from Chevron acquiring a portion of its

interest in TCO at a value greater than the underlying book value for that portion of

TCO’s net assets. See Note 6, on page FS-33, for summarized financial information

for 100 percent of TCO.

Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company

formed in 2008 to operate the Hamaca heavy-oil production and upgrading project.

The project, located in Venezuela’s Orinoco Belt, has a 25-year contract term. Prior

to the formation of Petropiar, Chevron had a 30 percent interest in the Hamaca

project. At December 31, 2012, the company’s carrying value of its investment in

Petropiar was approximately $180 less than the amount of underlying equity in

Petropiar’s net assets. The difference represents the excess of Chevron’s underlying

equity in Petropiar’s net assets over the net book value of the assets contributed to

the venture.

Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian

Pipeline Consortium, a variable interest entity, which provides the critical export

route for crude oil from both TCO and Karachaganak. The company joined the

consortium in 1997 and has investments and advances totaling $1,187 which includes

long-term loans of $1,179 at year-end 2012. The loans were provided to fund 30

percent of the initial pipeline construction. The company is not the primary beneficiary

of the consortium because it does not direct activities of the consortium and only

receives its proportionate share of the financial returns.

Petroboscan Chevron has a 39 percent interest in Petroboscan, a joint stock

company formed in 2006 to operate the Boscan Field in Venezuela until 2026.

Chevron previously operated the field under an operating service agreement. At

December 31, 2012, the company’s carrying value of its investment in Petroboscan

was approximately $200 higher than the amount of underlying equity in

Petroboscan’s net assets. The difference reflects the excess of the

net book value of the assets contributed by Chevron over its underlying equity in

Petroboscan’s net assets.

Angola LNG Ltd. Chevron has a 36 percent interest in Angola LNG Ltd., which

will process and liquefy natural gas produced in Angola for delivery to international

markets.

GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a

joint venture with GS Holdings. The joint venture imports, refines and markets

petroleum products and petrochemicals, predominantly in South Korea.

Chevron Phillips Chemical Company LLC Chevron owns 50 percent of

Chevron Phillips Chemical Company LLC. The other half is owned by Phillips 66.

Star Petroleum Refining Company Ltd. Chevron has a 64 percent ownership

interest in Star Petroleum Refining Company Ltd. (SPRC), which owns the Star

Refinery in Thailand. PTT Public Company Limited owns the remaining 36 percent

of SPRC. Due to a change in control effective June 2012, SPRC is consolidated in

Chevron's Consolidated Financial Statements.

Caltex Australia Ltd. Chevron has a 50 percent equity ownership interest in

Caltex Australia Ltd. (CAL). The remaining 50 percent of CAL is publicly owned.

At December 31, 2012, the fair value of Chevron’s share of CAL common stock

was $2,690.

Other Information “Sales and other operating revenues” on the Consolidated

Statement of Income includes $17,356, $20,164 and $13,672 with affiliated

companies for 2012, 2011 and 2010, respectively. “Purchased crude oil and

products” includes $6,634, $7,489 and $5,559 with affiliated companies for 2012,

2011 and 2010, respectively.

 “Accounts and notes receivable” on the Consolidated Balance Sheet includes

$1,207 and $1,968 due from affiliated companies at December 31, 2012 and 2011,

respectively. “Accounts payable” includes $407 and $519 due to affiliated companies

at December 31, 2012 and 2011, respectively.

FS-39
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 11 Investments and Advances - Continued

 The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron loans to

affiliates of $1,494, $957 and $1,543 at December 31, 2012, 2011 and 2010, respectively.

Affiliates Chevron Share

Year ended December 31 2012 2011 2010 2012 2011 2010

Total revenues $ 136,065 $ 140,107 $ 107,505 $ 65,196 $ 68,632 $ 52,088

Income before income tax expense 23,016 23,054 18,468 9,856 10,555 7,966

Net income attributable to affiliates 16,786 16,663 12,831 6,938 7,413 5,683

At December 31

Current assets $ 37,541 $ 35,573 $ 30,335 $ 14,732 $ 14,695 $ 12,845

Noncurrent assets 66,065 61,855 57,491 23,523 22,422 21,401

Current liabilities 27,878 24,671 20,428 11,093 11,040 9,363

Noncurrent liabilities 19,366 19,267 19,749 4,879 4,491 4,459

Total affiliates’ net equity $ 56,362 $ 53,490 $ 47,649 $ 22,283 $ 21,586 $ 20,424

Note 12

Properties, Plant and Equipment 1

At December 31 Year ended December 31

Gross Investment at Cost Net Investment Additions at Cost2,3 Depreciation Expense4

2012 2011 2010 2012 2011 2010 2012 2011 2010 2012 2011 2010

Upstream

 United

States $ 81,908 $ 74,369 $ 62,523 $ 37,909 $ 33,461 $ 23,277 $ 8,211 $ 14,404 $ 4,934 $ 3,902 $ 3,870 $ 4,078

 International 145,799 125,795 110,578 85,318 72,543 64,388 21,343 15,722 14,381 8,015 7,590 7,448

Total

Upstream 227,707 200,164 173,101 123,227 106,004 87,665 29,554 30,126 19,315 11,917 11,460 11,526

Downstream

 United

States 21,792 20,699 19,820 11,333 10,723 10,379 1,498 1,226 1,199 799 776 741

 International 8,990 7,422 9,697 3,930 2,995 3,948 2,544 443 361 308 332 451

Total

Downstream 30,782 28,121 29,517 15,263 13,718 14,327 4,042 1,669 1,560 1,107 1,108 1,192

All Other5

 United

States 4,959 5,117 4,722 2,845 2,872 2,496 415 591 259 384 338 341

 International 3 3 30 27 13 14 16 4 5 11 5 5 4

Total All

Other 4,992 5,147 4,749 2,858 2,886 2,512 419 596 270 389 343 345

Total United

States 108,659 100,185 87,065 52,087 47,056 36,152 10,124 16,221 6,392 5,085 4,984 5,160

Total

International 154,822 133,247 120,302 89,261 75,552 68,352 23,891 16,170 14,753 8,328 7,927 7,903

Total $ 263,481 $ 233,432 $ 207,367 $ 141,348 $ 122,608 $ 104,504 $ 34,015 $32,391 $ 21,145 $ 13,413 $ 12,911 $ 13,063

1 Other than the United States, Nigeria and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2012. Nigeria had PP&E of $17,485, $15,601

and $13,896 for 2012, 2011 and 2010, respectively. Australia had $21,770 and $12,423 in 2012 and 2011, respectively.

2 Net of dry hole expense related to prior years’ expenditures of $80, $45 and $82 in 2012, 2011 and 2010, respectively.

3 Includes properties acquired with the acquisition of Atlas Energy, Inc., in 2011.

4 Depreciation expense includes accretion expense of $629, $628 and $513 in 2012, 2011 and 2010, respectively.

5 Primarily mining operations, power generation businesses, real estate assets and management information systems.

Note 13

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 six

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. The company no longer uses MTBE in the manufacture of gasoline in

the United States.

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 represenFS-40
 Note 13 Litigation - Continued

tatives 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. 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 $18,900, 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 $8,400 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 $16,000 and $76,000 and that unjust enrichment should be assessed

in an amount between approximately $5,000 and $38,000. 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.

 On February 14, 2011, the provincial court in Lago Agrio rendered an adverse

judgment in the case. The court rejected Chevron’s defenses to the extent the court

addressed them in its opinion. The judgment assessed approximately $8,600 in

damages and approximately $900 as an award for the plaintiffs’ representatives. It

also assessed an additional amount of approximately $8,600 in punitive damages

unless the company issued a public apology within 15 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. On January 3, 2012, an appellate panel in the

provincial court affirmed the February 14, 2011 decision and ordered that Chevron

pay additional attorneys’ fees in the amount of “0.10% of the values that are derived

from the decisional act of this judgment.” The plaintiffs filed a petition to clarify

FS-41
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 13 Litigation - Continued

and amplify the appellate decision on January 6, 2012, and the court issued a ruling

in response on January 13, 2012, purporting to clarify and amplify its January 3,

2012 ruling, which included clarification that the deadline for the company to issue a

public apology to avoid the additional amount of approximately $8,600 in punitive

damages was within 15 days of the clarification ruling, or February 3, 2012.

Chevron did not issue an apology because doing so might be mischaracterized as an

admission of liability and would be contrary to facts and evidence submitted at trial.

On January 20, 2012, Chevron appealed (called a petition for cassation) the appellate

panel’s decision to Ecuador’s National Court of Justice. As part of the appeal,

Chevron requested the suspension of any requirement that Chevron post a bond to

prevent enforcement under Ecuadorian law of the judgment during the cassation

appeal. On February 17, 2012, the appellate panel of the provincial court admitted

Chevron’s cassation appeal in a procedural step necessary for the National Court of

Justice to hear the appeal. The provincial court appellate panel denied Chevron’s

request for a suspension of the requirement that Chevron post a bond and stated that

it would not comply with the First and Second Interim Awards of the international

arbitration tribunal discussed below. On March 29, 2012, the matter was transferred

from the provincial court to the National Court of Justice, and on November 22,

2012, the National Court agreed to hear Chevron's cassation appeal. On August 3,

2012, the provincial court in Lago Agrio approved a court-appointed liquidator’s

report on damages that calculated the total judgment in the case to be $19,100.

Chevron has no assets in Ecuador and the Lago Agrio plaintiffs' lawyers have stated

in press releases and through other media that they will seek to enforce the

Ecuadorian judgment in various countries and otherwise disrupt Chevron's

operations. On May 30, 2012, the Lago Agrio plaintiffs filed an action against

Chevron Corporation, Chevron Canada Limited, and Chevron Canada Finance

Limited in the Ontario Superior Court of Justice in Ontario, Canada, seeking to

recognize and enforce the Ecuadorian judgment. On June 27, 2012, the Lago Agrio

plaintiffs filed an action against Chevron Corporation in the Superior Court of Justice

in Brasilia, Brazil, seeking to recognize and enforce the Ecuadorian judgment. On

October 15, 2012, the provincial court in Lago Agrio issued an ex parte embargo

order that purports to order the seizure of assets belonging to separate Chevron

subsidiaries in Ecuador, Argentina and Colombia. On November 6, 2012, at the

request of the Lago Agrio plaintiffs, a court in Argentina issued a Freeze Order

against Chevron Argentina S.R.L. and another Chevron subsidiary, Ingeniero

Nortberto Priu, requiring shares of both companies to be "embargoed," requiring

third parties to withhold 40% of any payments due to Chevron Argentina S.R.L. and

ordering banks to withhold 40% of the funds in Chevron Argentina S.R.L. bank

accounts. On December 14th, 2012, the Argentinean court rejected a motion to

revoke the Freeze Order but modified it by ordering that third parties are not

required to withhold funds but must report their payments. The court also clarified

that the Freeze Order relating to bank accounts excludes taxes. On January 30,

2013, an appellate court upheld the Freeze Order. Chevron continues to believe the

provincial 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 or any enforcement action. Chevron expects to continue a vigorous defense

of any imposition of liability in the Ecuadorian courts and to contest and defend any

and all enforcement actions.

 Chevron and Texpet filed an arbitration claim in September 2009 against the

Republic of Ecuador before an arbitral tribunal presiding in 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 Tribunal 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. On January 25, 2012, the Tribunal converted the Order for Interim

Measures into an Interim Award. Chevron filed a renewed application for further

interim measures on January 4, 2012, and the Republic of Ecuador opposed

Chevron’s application and requested that the existing Order for Interim Measures be

vacated on January 9, 2012. On February 16, 2012, the Tribunal issued a Second

Interim Award mandating that the Republic of Ecuador take all measures necessary

(whether by its judicial, legislative or executive branches) to suspend or cause to be

suspended the enforcement and recognition within and without Ecuador of the

judgment against Chevron and, in particular, to preclude any certification by the

Republic of Ecuador that would cause the judgment to be enforceable against

Chevron. On February 27, 2012, the Tribunal issued a Third Interim Award

confirming its

FS-42
 Note 13 Litigation - Continued

jurisdiction to hear Chevron's arbitration claims. On April 9, 2012, the Tribunal

issued a scheduling order to hear issues relating to the scope of the settlement and

release agreements between the Republic of Ecuador and Texpet, and on July 9,

2012, the Tribunal indicated that it wanted to hear the remaining issues in January

2014. On February 7, 2013, the Tribunal issued its Fourth Interim Award in which

it declared that the Republic of Ecuador “has violated the First and Second Interim

Awards under the [BIT], the UNCITRAL Rules and international law in regard to

the finalization and enforcement subject to execution of the Lago Agrio Judgment

within and outside Ecuador, including (but not limited to) Canada, Brazil and

Argentina.” A schedule for the Tribunal’s order to show cause hearing will be issued

separately.

 Through a series of U.S. court proceedings initiated by Chevron to obtain

discovery relating to the Lago Agrio litigation and the BIT arbitration, Chevron

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 May 31, 2011, the Federal District

Court severed claims one through eight of Chevron’s complaint from the ninth claim

for declaratory relief and imposed a discovery stay on claims one through eight

pending a trial on the ninth claim for declaratory relief. On September 19, 2011, the

U.S. Court of Appeals for the Second Circuit vacated the preliminary injunction,

stayed the trial on Chevron’s ninth claim, a 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 issued its opinion on January 26,

2012 ordering the dismissal of Chevron’s ninth claim for declaratory relief. On

February 16, 2012, the Federal District Court lifted the stay on claims one through

eight, and on October 18, 2012, the Federal District Court set a trial date of October

15, 2013.

 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 Ecuadorian judgment, the 2008 engineer’s report on

alleged damages and the September 2010 plaintiffs’ submission on alleged damages,

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 14

Taxes

Income Taxes

Year ended December 31

2012 2011 2010

Taxes on income

U.S. federal

Current $ 1,703 $ 1,893 $ 1,501

Deferred 673 877 162

State and local

Current 652 596 376

Deferred (145) 41 20

Total United States 2,883 3,407 2,059

International

Current 15,626 16,548 10,483

Deferred 1,487 671 377

Total International 17,113 17,219 10,860

Total taxes on income $ 19,996 $ 20,626 $ 12,919

In 2012, before-tax income for U.S. operations, including related corporate and

other charges, was $8,456, compared with before-tax income of $10,222 and

$6,528 in 2011 and 2010, respectively. For international operations, before-tax

income was $37,876, $37,412 and $25,527 in 2012, 2011 and 2010, respectively.

U.S. federal income tax expense was reduced by $165, $191 and $162 in 2012,

2011 and 2010, respectively, for business tax credits. 

 The reconciliation between the U.S. statutory federal income tax rate and the

company’s effective income tax rate is detailed in the following table:

Year ended December 31

2012 2011 2010

U.S. statutory federal income tax rate 35.0 % 35.0 % 35.0 %

Effect of income taxes from international

operations at rates different from the

U.S. statutory rate 7.8 7.5 5.2

State and local taxes on income, net of

U.S. federal income tax benefit 0.6 0.9 0.8

Prior-year tax adjustments (0.2) (0.1) (0.6)

Tax credits (0.4) (0.4) (0.5)

Effects of changes in tax rates 0.3 0.5 —

Other 0.1 (0.1) 0.4

Effective tax rate 43.2 % 43.3 % 40.3 %

FS-43
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 14 Taxes - Continued

 The company’s effective tax rate decreased slightly from 43.3 percent in 2011 to

43.2 percent in 2012. The impact of lower effective tax rates in international upstream

operations was essentially offset by foreign currency remeasurement impacts between

periods. For international upstream, the lower effective tax rates in the current period

were driven primarily by the effects of asset sales, one-time tax benefits and reduced

withholding taxes, which were partially offset by a lower utilization of tax credits

during the current year. 

 The company records its deferred taxes on a tax-jurisdiction basis and classifies

those net amounts as current or noncurrent based on the balance sheet classification

of the related assets or liabilities. The reported deferred tax balances are composed of

the following:

At December 31

2012 2011

Deferred tax liabilities

Properties, plant and equipment $ 24,295 $ 23,597

Investments and other 2,276 2,271

Total deferred tax liabilities 26,571 25,868

Deferred tax assets

Foreign tax credits (10,817) (8,476)

Abandonment/environmental reserves (5,728) (5,387)

Employee benefits (5,100) (4,773)

Deferred credits (2,891) (1,548)

Tax loss carryforwards (738) (828)

Other accrued liabilities (381) (531)

Inventory (281) (360)

Miscellaneous (1,835) (1,595)

Total deferred tax assets (27,771) (23,498)

Deferred tax assets valuation allowance 15,443 11,096

Total deferred taxes, net $ 14,243 $ 13,466

 Deferred tax liabilities at the end of 2012 increased by approximately $700 from

year-end 2011. The increase was related to increased temporary differences for

property, plant and equipment.

 Deferred tax assets increased by approximately $4,300 in 2012. Increases

primarily related to additional U.S. foreign tax credits arising from earnings in hightax-rate international jurisdictions (which were substantially offset by a valuation

allowance) and to future international tax benefits earned.

 The overall valuation allowance relates to deferred tax assets for U.S. foreign tax

credit carryforwards, tax loss carryforwards and temporary differences. It reduces

the deferred tax assets to amounts that are, in management’s assessment, more likely

than not to be realized. At the end of 2012, the company had tax loss carryforwards

of approximately $2,009 and tax credit carryforwards of approximately $1,146

primarily related to various international tax jurisdictions. Whereas some of these tax

loss carryforwards do not have an expiration date, others expire at various times from 2013 through 2029. U.S. foreign tax

credit carryforwards of $10,817 will expire between 2013 and 2022.

 At December 31, 2012 and 2011, deferred taxes were classified on the

Consolidated Balance Sheet as follows:

At December 31

2012 2011

Prepaid expenses and other current assets $ (1,365) $ (1,149)

Deferred charges and other assets (2,662) (1,224)

Federal and other taxes on income 598 295

Noncurrent deferred income taxes 17,672 15,544

Total deferred income taxes, net $ 14,243 $ 13,466

 Income taxes are not accrued for unremitted earnings of international operations

that have been or are intended to be reinvested indefinitely. Undistributed earnings of

international consolidated subsidiaries and affiliates for which no deferred income tax

provision has been made for possible future remittances totaled $26,527 at

December 31, 2012. This amount represents earnings reinvested as part of the

company’s ongoing international business. It is not practicable to estimate the amount

of taxes that might be payable on the possible remittance of earnings that are intended

to be reinvested indefinitely. At the end of 2012, deferred income taxes were recorded

for the undistributed earnings of certain international operations where indefinite

reinvestment of the earnings is not planned. The company does not anticipate

incurring significant additional taxes on remittances of earnings that are not indefinitely

reinvested.

Uncertain Income Tax Positions Under accounting standards for uncertainty in

income taxes (ASC 740-10), a company recognizes a tax benefit in the financial

statements for an uncertain tax position only if management’s assessment is that the

position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be

allowed by the tax jurisdiction based solely on the technical merits of the position. The

term “tax position” in the accounting standards for income taxes refers to a position

in a previously filed tax return or a position expected to be taken in a future tax

return that is reflected in measuring current or deferred income tax assets and

liabilities for interim or annual periods.

 The following table indicates the changes to the company’s unrecognized tax

benefits for the years ended December 31, 2012, 2011 and 2010. The term

“unrecognized tax benefits” in the accounting standards for income taxes refers to the

differences between a tax position taken or expected to be taken in a tax return and

the benefit measured and recognized in the financial statements. Interest and penalties

are not included.

FS-44
 Note 14 Taxes - Continued

2012 2011 2010

Balance at January 1 $ 3,481 $ 3,507 $ 3,195

Foreign currency effects 4 (2) 17

Additions based on tax positions 

taken in current year 543 469 334

Additions/reductions resulting from

current-year asset acquisitions/sales — (41) —

Additions for tax positions taken 

in prior years 152 236 270

Reductions for tax positions taken in prior

years (899) (366) (165)

Settlements with taxing authorities in

current year (138) (318) (136)

Reductions as a result of a lapse 

of the applicable statute of limitations (72) (4) (8)

Balance at December 31 $ 3,071 $ 3,481 $ 3,507

 The decrease in unrecognized tax benefits between December 31, 2011, and

December 31, 2012 was primarily due to new information received during the fourth

quarter 2012 regarding the sustainability of certain U.S. foreign tax credits. The

reduction in unrecognized tax benefits related to these foreign tax credits had no

impact on the effective tax rate since the deferred tax asset recognized for these

foreign tax credits has been offset with a full valuation allowance.

Approximately 67 percent of the $3,071 of unrecognized tax benefits at

December 31, 2012, would have an impact on the effective tax rate if subsequently

recognized. Certain of these unrecognized tax benefits relate to tax carryforwards that

may require a full valuation allowance at the time of any such recognition.

 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 December 31, 2012. For these jurisdictions, the latest years for

which income tax examinations had been finalized were as follows: United States –

2007, Nigeria – 2000, Angola – 2001, Saudi Arabia – 2003 and Kazakhstan –

2006.

 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.

The company is currently assessing the potential impact of an August 2012 decision

by the U.S. Court of Appeals for the Third Circuit that disallows the Historic

Rehabilitation Tax Credits (HRTCs) claimed by an unrelated taxpayer. The company

has claimed a significant amount of HRTCs on its U.S. federal income tax returns in

open years, and it is reasonably possible that the specific findings from management's

ongoing assessment and evaluation could result in a significant increase in the

company's unrecognized tax benefit within the next 12 months. Any such increase

would impact the effective tax rate.

 On the Consolidated Statement of Income, the company reports interest and

penalties related to liabilities for uncertain tax positions as “Income tax expense.” As

of December 31, 2012, accruals of $293 for anticipated interest and penalty

obligations were included on the Consolidated Balance Sheet, compared with accruals

of $118 as of year-end 2011. Income tax expense (benefit) associated with interest

and penalties was $145, $(64) and $40 in 2012, 2011 and 2010, respectively.

Taxes Other Than on Income

Year ended December 31

2012 2011 2010

United States

Excise and similar taxes 

on products and merchandise $ 4,665 $ 4,199 $ 4,484

Import duties and other levies 1 4 —

Property and other 

miscellaneous taxes 782 726 567

Payroll taxes 240 236 219

Taxes on production 328 308 271

Total United States 6,016 5,473 5,541

International

Excise and similar taxes on 

products and merchandise 3,345 3,886 4,107

Import duties and other levies 106 3,511 6,183

Property and other 

miscellaneous taxes 2,501 2,354 2,000

Payroll taxes 160 148 133

Taxes on production 248 256 227

Total International 6,360 10,155 12,650

Total taxes other than on income $ 12,376 $ 15,628 $ 18,191

FS-45
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 

Note 15

Short-Term Debt

At December 31

2012 2011

Commercial paper* $ 2,783 $ 2,498

Notes payable to banks and others with 

originating terms of one year or less 23 40

Current maturities of long-term debt 20 17

Current maturities of long-term 

capital leases 38 54

Redeemable long-term obligations

Long-term debt 3,151 3,317

Capital leases 12 14

Subtotal 6,027 5,940

Reclassified to long-term debt (5,900) (5,600)

Total short-term debt $ 127 $ 340

* Weighted-average interest rates at December 31, 2012 and 2011, were 0.13 percent and 0.04 percent,

respectively.

Redeemable long-term obligations consist primarily of tax-exempt variable-rate put

bonds that are included as current liabilities because they become redeemable at the

option of the bondholders during the year following the balance sheet date.

 The company may periodically enter into interest rate swaps on a portion of its

short-term debt. At December 31, 2012, the company had no interest rate swaps on

short-term debt.

 At December 31, 2012, the company had $6,000 in committed credit facilities

with various major banks, expiring in December 2016, that 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 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 December 31, 2012.

 At December 31, 2012 and 2011, the company classified $5,900 and $5,600,

respectively, of short-term debt as long-term. Settlement of these obligations is not

expected to require the use of working capital within one year, as the company has

both the intent and the ability, as evidenced by committed credit facilities, to refinance

them on a long-term basis.

Note 16

Long-Term Debt

Total long-term debt, excluding capital leases, at December 31, 2012, was $11,966.

The company’s long-term debt outstanding at year-end 2012 and 2011 was as

follows:

At December 31

2012 2011

3.95% notes due 2014 $ — $ 1,998

1.104% notes due 2017 2,000 —

2.355% notes due 2022 2,000 —

4.95% notes due 2019 1,500 1,500

8.625% debentures due 2032 147 147

8.625% debentures due 2031 107 107

7.5% debentures due 2043 83 83

8% debentures due 2032 74 74

9.75% debentures due 2020 54 54

7.327% amortizing notes due 20141 43 59

8.875% debentures due 2021 40 40

Medium-term notes, maturing from 

2021 to 2038 (5.92%)2 38 38

Other long-term debt (8.07%) 2 — 1

Total including debt due within one year 6,086 4,101

 Debt due within one year (20) (17)

 Reclassified from short-term debt 5,900 5,600

Total long-term debt $ 11,966 $ 9,684

1 Guarantee of ESOP debt.

2 Weighted-average interest rate at December 31, 2012 and 2011.

 In November 2012, the company filed with the SEC an automatic registration

statement that expires in 2015. This registration statement is for an unspecified

amount of nonconvertible debt securities issued or guaranteed by the company.

 Long-term debt of $6,086 matures as follows: 2013 – $20; 2014 – $23; 2015

– $0; 2016 – $0; 2017 – $2,000; and after 2017 – $4,043.

 In December 2012, $4,000 of Chevron Corporation bonds were issued and

$2,000 of Chevron Corporation 3.95% bonds due 2014 were redeemed early.

 See Note 8, beginning on page FS-33, for information concerning the fair value

of the company’s long-term debt.

FS-46
Note 17

New Accounting Standards

Balance Sheet (Topic 210), Disclosures about Offsetting Assets and

Liabilities (ASU 2011-11) In December 2011, the FASB issued ASU 2011-11,

which became effective for the company on January 1, 2013. The standard amends

and expands disclosure requirements about offsetting and related arrangements. The

company does not anticipate any impacts to its results of operations, financial position

or liquidity when the guidance becomes effective.

Comprehensive Income (Topic 220) Reporting of Amounts Reclassified

Out of Accumulated Other Comprehensive Income (ASU 2013-02) The

FASB issued ASU 2013-02 in February 2013. This standard became effective for

the company on January 1, 2013. ASU 2013-02 changes the presentation

requirements of significant reclassifications out of accumulated other comprehensive

income in their entirety and their corresponding effect on net income. For other

significant amounts that are not required to be reclassified in their entirety, the

standard requires the company to cross-reference to related footnote disclosures.

Adoption of the standard is not expected to have a significant impact on the

company's financial statement presentation.

Note 18

Accounting for Suspended Exploratory Wells

Accounting standards for the costs of exploratory wells (ASC 932) provide that

exploratory well costs continue to be capitalized after the completion of drilling when

(a) the well has found a sufficient quantity of reserves to justify completion as a

producing well, and (b) the entity is making sufficient progress assessing the reserves

and the economic and operating viability of the project. If either condition is not met

or if an enterprise obtains information that raises substantial doubt about the

economic or operational viability of the project, the exploratory well would be

assumed to be impaired, and its costs, net of any salvage value, would be charged to

expense. (Note that an entity is not required to complete the exploratory well as a

producing well.) The accounting standards provide a number of indicators that can

assist an entity in demonstrating that sufficient progress is being made in assessing the

reserves and economic viability of the project.

The following table indicates the changes to the company’s suspended exploratory

well costs for the three years ended December 31, 2012:

2012 2011 2010

Beginning balance at January 1 $ 2,434 $ 2,718 $ 2,435

Additions to capitalized exploratory well

costs pending the determination of proved

reserves 595 652 482

Reclassifications to wells, facilities 

and equipment based on the 

determination of proved reserves (244) (828) (129)

Capitalized exploratory well costs 

charged to expense (49) (45) (70)

Other reductions* (55) (63) —

Ending balance at December 31 $ 2,681 $ 2,434 $ 2,718

 *Represents property sales.

 The following table provides an aging of capitalized well costs and the number of

projects for which exploratory well costs have been capitalized for a period greater

than one year since the completion of drilling.

At December 31

2012 2011 2010

Exploratory well costs capitalized 

for a period of one year or less $ 501 $ 557 $ 419

Exploratory well costs capitalized 

for a period greater than one year 2,180 1,877 2,299

Balance at December 31 $ 2,681 $ 2,434 $ 2,718

Number of projects with exploratory well

costs that have been capitalized for a period

greater than one year* 46 47 53

* Certain projects have multiple wells or fields or both.

 Of the $2,180 of exploratory well costs capitalized for more than one year at

December 31, 2012, $1,359 (23 projects) is related to projects that had drilling

activities under way or firmly planned for the near future. The $821 balance is

related to 23 projects in areas requiring a major capital expenditure before production

could begin and for which additional drilling efforts were not under way or firmly

planned for the near future. Additional drilling was not deemed necessary because the

presence of hydrocarbons had already been established, and other activities were in

process to enable a future decision on project development.

FS-47
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 18 Accounting for Suspended Exploratory Wells - Continued

 The projects for the $821 referenced above had the following activities associated

with assessing the reserves and the projects’ economic viability: (a) $359 (six

projects) – undergoing front-end engineering and design with final investment

decision expected within three years; (b) $218 (four projects) – development concept

under review by government; (c) $202 (five projects) – development alternatives

under review; (d) $42 (eight projects) – miscellaneous activities for projects with

smaller amounts suspended. While progress was being made on all 46 projects, the

decision on the recognition of proved reserves under SEC rules in some cases may

not occur for several years because of the complexity, scale and negotiations

connected with the projects. However, the majority of these decisions are expected to

occur in the next three years.

 The $2,180 of suspended well costs capitalized for a period greater than one year

as of December 31, 2012, represents 166 exploratory wells in 46 projects. The tables

below contain the aging of these costs on a well and project basis:

Aging based on drilling completion date of individual

wells: Amount

Number

of wells

1997–2001 $ 6 5 23

2002–2006 416 41

2007–2011 1,699 102

Total $ 2,180 166

Aging based on drilling completion date of last

suspended well in project: Amount

Number

of projects

1999 $ 8 1

2003–2007 322 8

2008–2012 1,850 37

Total $ 2,180 46

Note 19

Stock Options and Other Share-Based Compensation

Compensation expense for stock options for 2012, 2011 and 2010 was $283 ($184

after tax), $265 ($172 after tax) and $229 ($149 after tax), respectively. In addition,

compensation expense for stock appreciation rights, restricted stock, performance

units and restricted stock units was $177 ($115 after tax), $214 ($139 after tax) and

$194 ($126 after tax) for 2012, 2011 and 2010, respectively. No significant stockbased compensation cost was capitalized at December 31, 2012, or December 31,

2011.

 Cash received in payment for option exercises under all share-based payment

arrangements for 2012, 2011 and 2010 was $753, $948 and $385, respectively.

Actual tax benefits realized for the tax deductions from option exercises were $101,

$121 and $66 for 2012, 2011 and 2010, respectively.

 Cash paid to settle performance units and stock appreciation rights was $123,

$151 and $140 for 2012, 2011 and 2010, respectively.

Chevron Long-Term Incentive Plan (LTIP) Awards under the LTIP may take

the form of, but are not limited to, stock options, restricted stock, restricted stock

units, stock appreciation rights, performance units and nonstock grants. From

April 2004 through January 2014, no more than 160 million shares may be issued

under the LTIP, and no more than 64 million of those shares may be in a form other

than a stock option, stock appreciation right or award requiring full payment for

shares by the award recipient. For the major types of awards outstanding as of

December 31, 2012, the contractual terms vary between three years for the

performance units and 10 years for the stock options and stock appreciation rights.

Unocal Share-Based Plans (Unocal Plans) When Chevron acquired Unocal in

August 2005, outstanding stock options and stock appreciation rights granted under

various Unocal Plans were exchanged for fully vested Chevron options and

appreciation rights. These awards retained the same provisions as the original Unocal

Plans. Unexercised awards began expiring in early 2010 and will continue to expire

through early 2015.

FS-48
 Note 19 Stock Options and Other Share-Based Compensation - Continued

 The fair market values of stock options and stock appreciation rights granted in

2012, 2011 and 2010 were measured on the date of grant using the Black-Scholes

option-pricing model, with the following weighted-average assumptions:

Year ended December 31

2012 2011 2010

Stock Options

Expected term in years1 6.0 6.2 6.1

Volatility2 31.7 % 31.0 % 30.8 %

Risk-free interest rate based on zero

coupon U.S. treasury note 1.1 % 2.6 % 2.9 %

Dividend yield 3.2 % 3.6 % 3.9 %

Weighted-average fair value per option

granted $ 23.35 $ 21.24 $ 16.28

1 Expected term is based on historical exercise and postvesting cancellation data.

2 Volatility rate is based on historical stock prices over an appropriate period, generally equal to the

expected term.

 A summary of option activity during 2012 is presented below:

Weighted- Average

Average Remaining Aggregate

Shares Exercise Contractual Intrinsic

(Thousands) Price Term (Years) Value

Outstanding at 

January 1, 2012 72,348 $ 73.71

Granted 12,455 $ 107.73

Exercised (12,024) $ 62.13

Forfeited (884) $ 96.78

Outstanding at 

December 31, 2012 71,895 $ 81.26 6.3 $ 1,933

Exercisable at 

December 31, 2012 47,060 $ 72.82 5.2 $ 1,662

 The total intrinsic value (i.e., the difference between the exercise price and the

market price) of options exercised during 2012, 2011 and 2010 was $580, $668

and $259, respectively. During this period, the company continued its practice of

issuing treasury shares upon exercise of these awards.

 As of December 31, 2012, there was $255 of total unrecognized before-tax

compensation cost related to nonvested share-based

compensation arrangements granted under the plans. That cost is expected to be

recognized over a weighted-average period of 1.7 years.

 At January 1, 2012, the number of LTIP performance units outstanding was

equivalent to 2,881,836 shares. During 2012, 888,350 units were granted,

882,003 units vested with cash proceeds distributed to recipients and 60,426 units

were forfeited. At December 31, 2012, units outstanding were 2,827,757, and the

fair value of the liability recorded for these instruments was $320. In addition,

outstanding stock appreciation rights and other awards that were granted under

various LTIP and former Unocal programs totaled approximately 2.4 million

equivalent shares as of December 31, 2012. A liability of $71 was recorded for these

awards.

Note 20

Employee Benefit Plans

The company has defined benefit pension plans for many employees. The company

typically prefunds defined benefit plans as required by local regulations or in certain

situations where 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 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.

 Under accounting standards for postretirement benefits (ASC 715), the

company recognizes the overfunded or underfunded status of each of its defined

benefit pension and OPEB plans as an asset or liability on the Consolidated Balance

Sheet.

FS-49
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 20 Employee Benefit Plans - Continued

 The funded status of the company’s pension and other postretirement benefit plans for 2012 and 2011 follows:

Pension Benefits

2012 2011 Other Benefits

U.S. Int’l. U.S. Int’l. 2012 2011

Change in Benefit Obligation

Benefit obligation at January 1 $ 12,165 $ 5,519 $ 10,271 $ 5,070 $ 3,765 $ 3,605

Service cost 452 181 374 174 61 58

Interest cost 435 320 463 325 153 180

Plan participants’ contributions — 7 — 6 151 148

Plan amendments 94 37 — 27 11 —

Actuarial loss (gain) 1,322 417 1,920 318 44 149

Foreign currency exchange rate changes — 114 — (98) 1 (19)

Benefits paid (763) (308) (863) (303) (350) (346)

Divestitures (51) — — — (49) —

Curtailment — — — — — (10)

Benefit obligation at December 31 13,654 6,287 12,165 5,519 3,787 3,765

Change in Plan Assets

Fair value of plan assets at January 1 8,720 3,577 8,579 3,503 — —

Actual return on plan assets 1,149 375 (143) 118 — —

Foreign currency exchange rate changes — 90 — (66) — —

Employer contributions 844 384 1,147 319 199 198

Plan participants’ contributions — 7 — 6 151 148

Benefits paid (763) (308) (863) (303) (350) (346)

Divestitures (41) — — — — —

Fair value of plan assets at December 31 9,909 4,125 8,720 3,577 — —

Funded Status at December 31 $ (3,745) $ (2,162) $ (3,445) $ (1,942) $ (3,787) $ (3,765)

 Amounts recognized on the Consolidated Balance Sheet for the company’s pension and other postretirement benefit plans at December 31, 2012 and 2011, include:

Pension Benefits

2012 2011 Other Benefits

U.S. Int’l. U.S. Int’l. 2012 2011

Deferred charges and other assets $ 7 $ 55 $ 5 $ 116 $ — $ —

Accrued liabilities (61) (76) (72) (84) (225) (222)

Reserves for employee benefit plans (3,691) (2,141) (3,378) (1,974) (3,562) (3,543)

Net amount recognized at December 31 $ (3,745) $ (2,162) $ (3,445) $ (1,942) $ (3,787) $ (3,765)

 Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $9,742 and $9,279 at the end of

2012 and 2011, respectively. These amounts consisted of:

Pension Benefits

2012 2011 Other Benefits

U.S. Int’l. U.S. Int’l. 2012 2011

Net actuarial loss $ 6,087 $ 2,439 $ 5,982 $ 2,250 $ 968 $ 1,002

Prior service (credit) costs 58 170 (44) 152 20 (63)

Total recognized at December 31 $ 6,145 $ 2,609 $ 5,938 $ 2,402 $ 988 $ 939

 The accumulated benefit obligations for all U.S. and international pension plans were $12,108 and $5,167, respectively, at December 31, 2012, and $11,198 and $4,518,

respectively, at December 31, 2011.

FS-50
 Note 20 Employee Benefit Plans - Continued

 Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2012 and 2011, was:

Pension Benefits

2012 2011

U.S. Int’l. U.S. Int’l.

Projected benefit obligations $ 13,647 $ 4,812 $ 12,157 $ 4,207

Accumulated benefit obligations 12,101 4,063 11,191 3,586

Fair value of plan assets 9,895 2,756 8,707 2,357

 The components of net periodic benefit cost and amounts recognized in other comprehensive income for 2012, 2011 and 2010 are shown in the table below:

Pension Benefits

2012 2011 2010 Other Benefits

U.S. Int’l. U.S. Int’l. U.S. Int’l. 2012 2011 2010

Net Periodic Benefit Cost

Service cost $ 452 $ 181 $ 374 $ 174 $ 337 $ 153 $ 61 $ 58 $ 39

Interest cost 435 320 463 325 486 307 153 180 175

Expected return on plan assets (634) (269) (613) (283) (538) (241) — — —

Amortization of prior service (credits) costs (7) 18 (8) 19 (8) 22 (72) (72) (75)

Recognized actuarial losses 470 136 310 101 318 98 56 64 27

Settlement losses 220 5 298 — 186 6 (26) — —

Curtailment losses (gains) — — — 35 — — — (10) —

Total net periodic benefit cost 936 391 824 371 781 345 172 220 166

Changes Recognized in Other Comprehensive Income

Net actuarial loss during period 805 330 2,671 448 242 118 45 131 497

Amortization of actuarial loss (700) (141) (608) (101) (504) (104) (79) (64) (27)

Prior service cost during period 94 37 — 27 — — 11 — 12

Amortization of prior service credits (costs) 7 (18) 8 (54) 8 (22) 72 72 75

Total changes recognized in other 

comprehensive income 206 208 2,071 320 (254) (8) 49 139 557

Recognized in Net Periodic Benefit Cost and Other

Comprehensive Income $ 1,142 $ 599 $ 2,895 $ 691 $ 527 $ 337 $ 221 $ 359 $ 723

 Net actuarial losses recorded in “Accumulated other comprehensive loss” at

December 31, 2012, for the company’s U.S. pension, international pension and

OPEB plans are being amortized on a straight-line basis over approximately 10, 13

and 10 years, respectively. These amortization periods represent the estimated

average remaining service of employees expected to receive benefits under the plans.

These losses are amortized to the extent they exceed 10 percent of the higher of the

projected benefit obligation or market-related value of plan assets. The amount

subject to amortization is determined on a plan-by-plan basis. During 2013, the

company estimates actuarial losses of $472, $143 and $54 will be amortized from

“Accumulated other comprehensive loss” for U.S. pension, international pension

and

OPEB plans, respectively. In addition, the company estimates an additional $230 will

be recognized from “Accumulated other comprehensive loss” during 2013 related to

lump-sum settlement costs from U.S. pension plans.

 The weighted average amortization period for recognizing prior service costs

(credits) recorded in “Accumulated other comprehensive loss” at December 31,

2012, was approximately 10 and 13 years for U.S. and international pension plans,

respectively, and 11 years for other postretirement benefit plans. During 2013, the

company estimates prior service (credits) costs of $1, $22 and $(50) will be

amortized from “Accumulated other comprehensive loss” for U.S. pension,

international pension and OPEB plans, respectively.

FS-51
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 20 Employee Benefit Plans - Continued

Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:

Pension Benefits

2012 2011 2010 Other Benefits

U.S. Int’l. U.S. Int’l. U.S. Int’l. 2012 2011 2010

Assumptions used to determine benefit obligations:

Discount rate 3.6% 5.2% 3.8% 5.9% 4.8% 6.5% 4.1% 4.2% 5.2%

Rate of compensation increase 4.5% 5.5% 4.5% 5.7% 4.5% 6.7% N/A N/A N/A

Assumptions used to determine net periodic benefit cost:

Discount rate 3.8% 5.9% 4.8% 6.5% 5.3% 6.8% 4.2% 5.2% 5.9%

Expected return on plan assets 7.5% 7.5% 7.8% 7.8% 7.8% 7.8% N/A N/A N/A

Rate of compensation increase 4.5% 5.7% 4.5% 6.7% 4.5% 6.3% N/A N/A N/A

Expected Return on Plan Assets The company’s estimated long-term rates of

return on pension assets are driven primarily by actual historical asset-class returns,

an assessment of expected future performance, advice from external actuarial firms

and the incorporation of specific asset-class risk factors. Asset allocations are

periodically updated using pension plan asset/liability studies, and the company’s

estimated long-term rates of return are consistent with these studies.

 For 2012, the company used an expected long-term rate of return of 7.5 percent

for U.S. pension plan assets, which account for 70 percent of the company’s pension

plan assets. In 2011 and 2010, the company used a long-term rate of return of 7.8

percent for this plan.

 The market-related value of assets of the major U.S. pension plan used in the

determination of pension expense was based on the market values in the three months

preceding the year-end measurement date. Management considers the three-month

time period long enough to minimize the effects of distortions from day-to-day

market volatility and still be contemporaneous to the end of the year. For other plans,

market value of assets as of year-end is used in calculating the pension expense.

Discount Rate The discount rate assumptions used to determine the U.S. and

international pension and postretirement benefit plan obligations and expense reflect

the rate at which benefits could be effectively settled and is equal to the equivalent

single rate resulting from yield curve analysis. This analysis considered the projected

benefit payments specific to the company's plans and the yields on high-quality bonds.

At December 31, 2012, the company used a 3.6 percent discount rate for the U.S.

pension plans and 3.9 percent for the main U.S. OPEB plan. The discount rates at

the end of 2011 and 2010 were 3.8 and 4.0 percent and 4.8 and 5.0 percent for the

U.S. pension plans and the main U.S. OPEB plans, respectively.

Other Benefit Assumptions For the measurement of accumulated postretirement

benefit obligation at December 31, 2012, for the main U.S. postretirement medical

plan, the assumed health care cost-trend rates start with 7.5 percent in 2013 and

gradually decline to 4.5 percent for 2025 and beyond. For this measurement at

December 31, 2011, the assumed health care cost-trend rates started with 8 percent

in 2012 and gradually declined to 5 percent for 2023 and beyond. In both

measurements, the annual increase to company contributions was capped at 4

percent.

 Assumed health care cost-trend rates can have a significant effect on the amounts

reported for retiree health care costs. The impact is mitigated by the 4 percent cap on

the company’s medical contributions for the primary U.S. plan. A 1-percentage-point

change in the assumed health care cost-trend rates would have the following effects:

1 Percent 1 Percent

Increase Decrease

Effect on total service and interest cost components $ 16 $ (13)

Effect on postretirement benefit obligation $ 165 $ (141)

Plan Assets and Investment Strategy The fair value hierarchy of inputs the

company uses to value the pension assets is divided into three levels:

 Level 1: Fair values of these assets are measured using unadjusted quoted prices

for the assets or the prices of identical assets in active markets that the plans have the

ability to access.

 Level 2: Fair values of these assets are measured based on quoted prices for

similar assets in active markets; quoted prices for identical or similar assets in inactive

markets; inputs other than quoted prices that are observable for the asset; and inputs

FS-52
 Note 20 Employee Benefit Plans - Continued

that are derived principally from or corroborated by observable market data through

correlation or other means. If the asset has a contractual term, the Level 2 input is

observable for substantially the full term of the asset. The fair values for Level 2

assets are generally obtained from third-party broker quotes, independent pricing

services and exchanges.

 Level 3: Inputs to the fair value measurement are unobservable for these assets.

Valuation may be performed using a financial model with estimated inputs entered

into the model.

 The fair value measurements of the company’s pension plans for 2012 and 2011

are below:

U.S. Int’l.

Total Fair Value Level 1 Level 2 Level 3 Total Fair Value Level 1 Level 2 Level 3

At December 31, 2011

Equities

U.S.1 $ 1,470 $ 1,470 $ — $ — $ 497 $ 497 $ — $ —

International 1,203 1,203 — — 693 693 — —

Collective Trusts/Mutual Funds2 2,633 14 2,619 — 596 28 568 —

Fixed Income

Government 622 146 476 — 635 25 610 —

Corporate 338 — 338 — 319 16 276 27

Mortgage-Backed Securities 107 — 107 — 2 — — 2

Other Asset Backed 61 — 61 — 5 — 5 —

Collective Trusts/Mutual Funds2 1,046 — 1,046 — 345 61 284 —

Mixed Funds3 10 10 — — 102 13 89 —

Real Estate4 843 — — 843 155 — — 155

Cash and Cash Equivalents 404 404 — — 211 211 — —

Other5 (17) (79) 8 54 17 (2) 17 2

Total at December 31, 2011 $ 8,720 $ 3,168 $ 4,655 $ 897 $ 3,577 $ 1,542 $ 1,849 $ 186

At December 31, 2012

Equities

U.S.1 $ 1,709 $ 1,709 $ — $ — $ 334 $ 334 $ — $ —

International 1,263 1,263 — — 520 520 — —

Collective Trusts/Mutual Funds2 2,979 7 2,972 — 1,233 402 831 —

Fixed Income

Government 435 396 39 — 578 40 538 —

Corporate 384 — 384 — 230 25 175 30

Mortgage-Backed Securities 65 — 65 — 2 — — 2

Other Asset Backed 51 — 51 — 4 — 4 —

Collective Trusts/Mutual Funds2 1,520 — 1,520 — 671 26 645 —

Mixed Funds3 — — — — 115 4 111 —

Real Estate4 1,114 — — 1,114 177 — — 177

Cash and Cash Equivalents 373 373 — — 222 204 18 —

Other5 16 (44) 5 55 39 (3) 40 2

Total at December 31, 2012 $ 9,909 $ 3,704 $ 5,036 $ 1,169 $ 4,125 $ 1,552 $ 2,362 $ 211

1 U.S. equities include investments in the company’s common stock in the amount of $27 at December 31, 2012, and $35 at December 31, 2011.

2 Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly index funds. For these index funds, the Level 2 designation is partially based on the restriction that advance

notification of redemptions, typically two business days, is required.

3 Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.

4 The year-end valuations of the U.S. real estate assets are based on internal appraisals by the real estate managers, which are updates of third-party appraisals that occur at least once a year for each property in the portfolio.

5 The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1); dividends and interest- and tax-related receivables (Level 2); insurance contracts and investments in private-equity limited

partnerships (Level 3).

FS-53
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 20 Employee Benefit Plans - Continued

 The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:

Fixed Income

Mortgage-Backed

Corporate Securities Real Estate Other Total

Total at December 31, 2010 $ 28 $ 2 $ 738 $ 55 $ 823

Actual Return on Plan Assets:

 Assets held at the reporting date — — 103 4 107

 Assets sold during the period — — 1 (2) (1)

Purchases, Sales and Settlements (1) — 156 (1) 154

Transfers in and/or out of Level 3 — — — — —

Total at December 31, 2011 $ 27 $ 2 $ 998 $ 56 $ 1,083

Actual Return on Plan Assets:

 Assets held at the reporting date — — 108 1 109

 Assets sold during the period — — 2 — 2

Purchases, Sales and Settlements 4 — 182 — 186

Transfers in and/or out of Level 3 — — — — —

Total at December 31, 2012 $ 31 $ 2 $ 1,290 $ 57 $ 1,380

 The primary investment objectives of the pension plans are to achieve the highest

rate of total return within prudent levels of risk and liquidity, to diversify and mitigate

potential downside risk associated with the investments, and to provide adequate

liquidity for benefit payments and portfolio management.

 The company’s U.S. and U.K. pension plans comprise 87 percent of the total

pension assets. Both the U.S. and U.K. plans have an Investment Committee that

regularly meets during the year to review the asset holdings and their returns. To

assess the plans’ investment performance, long-term asset allocation policy

benchmarks have been established.

 For the primary U.S. pension plan, the company's Benefit Plan Investment

Committee has established the following approved asset allocation ranges: Equities

40–70 percent, Fixed Income and Cash 20–65 percent, Real Estate 0–15 percent,

and Other 0–5 percent. For the U.K. pension plan, the U.K. Board of Trustees has

established the following asset allocation guidelines, which are reviewed regularly:

Equities 50–70 percent and Fixed Income and Cash 30–50 percent. The other

significant international pension plans also have established maximum and minimum

asset allocation ranges that vary by plan. Actual asset allocation within approved

ranges is based on a variety of current economic and market conditions and

consideration of specific asset class risk. To mitigate concentration and other risks,

assets are invested across multiple asset classes with active investment managers and

passive index funds.

 The company does not prefund its OPEB obligations.

Cash Contributions and Benefit Payments In 2012, the company contributed

$844 and $384 to its U.S. and international pension plans, respectively. In 2013, the

company expects contributions to be approximately $650

and $350 to its U.S. and international pension plans, respectively. Actual

contribution amounts are dependent upon investment returns, changes in pension

obligations, regulatory environments and other economic factors. Additional funding

may ultimately be required if investment returns are insufficient to offset increases in

plan obligations.

 The company anticipates paying other postretirement benefits of approximately

$228 in 2013, compared with $199 paid in 2012.

 The following benefit payments, which include estimated future service, are

expected to be paid by the company in the next 10 years:

Pension Benefits Other

U.S. Int’l. Benefits

2013 $ 1,188 $ 273 $ 228

2014 $ 1,192 $ 338 $ 234

2015 $ 1,179 $ 265 $ 239

2016 $ 1,180 $ 291 $ 245

2017 $ 1,184 $ 386 $ 249

2018-2022 $ 5,650 $ 2,353 $ 1,292

Employee Savings Investment Plan Eligible employees of Chevron and certain of

its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP).

 Charges to expense for the ESIP represent the company’s contributions to the

plan, which are funded either through the purchase of shares of common stock on

the open market or through the release of common stock held in the leveraged

employee stock ownership plan (LESOP), which is described in the section that

follows. Total company matching contributions to employee accounts within the ESIP

were $286, $263 and $253 in 2012, 2011 and 2010, respectively. This cost was

reduced by the value of shares released from the LESOP totaling $43, $38 and $97

in 2012, 2011 and 2010,

FS-54
 Note 20 Employee Benefit Plans - Continued

respectively. The remaining amounts, totaling $243, $225 and $156 in 2012, 2011

and 2010, respectively, represent open market purchases.

Employee Stock Ownership Plan Within the Chevron ESIP is an employee stock

ownership plan (ESOP). In 1989, Chevron established a LESOP as a constituent part

of the ESOP. The LESOP provides partial prefunding of the company’s future

commitments to the ESIP.

 As permitted by accounting standards for share-based compensation (ASC 718),

the debt of the LESOP is recorded as debt, and shares pledged as collateral are

reported as “Deferred compensation and benefit plan trust” on the Consolidated

Balance Sheet and the Consolidated Statement of Equity.

 The company reports compensation expense equal to LESOP debt principal

repayments less dividends received and used by the LESOP for debt service. Interest

accrued on LESOP debt is recorded as interest expense. Dividends paid on LESOP

shares are reflected as a reduction of retained earnings. All LESOP shares are

considered outstanding for earnings-per-share computations.

 Total expense (credits) for the LESOP were $1, $(1) and $(1) in 2012, 2011 and

2010, respectively. The net credit for the respective years was composed of credits to

compensation expense of $2, $5 and $6 and charges to interest expense for LESOP

debt of $3, $4 and $5.

 Of the dividends paid on the LESOP shares, $18, $18 and $46 were used in

2012, 2011 and 2010, respectively, to service LESOP debt. No contributions were

required in 2011 or 2010, as dividends received by the LESOP were sufficient to

satisfy LESOP debt service. In 2012, the company contributed $2 to the LESOP.

 Shares held in the LESOP are released and allocated to the accounts of plan

participants based on debt service deemed to be paid in the year in proportion to the

total of current-year and remaining debt service. LESOP shares as of December 31,

2012 and 2011, were as follows:

Thousands 2012 2011

Allocated shares 18,055 19,047

Unallocated shares 1,292 1,864

Total LESOP shares 19,347 20,911

Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a

benefit plan trust for funding obligations under some of its benefit plans. At year-end

2012, the trust contained 14.2 million shares of Chevron treasury stock. The trust

will sell the shares or use the dividends from the shares to pay benefits only to the

extent that the company does not pay such benefits. The company intends to

continue to pay its obligations under the benefit plans. The trustee will vote the

shares held in the trust as instructed by the trust’s

beneficiaries. The shares held in the trust are not considered outstanding for earningsper-share purposes until distributed or sold by the trust in payment of benefit

obligations.

 Prior to its acquisition by Chevron, Unocal established various grantor trusts to

fund obligations under some of its benefit plans, including the deferred compensation

and supplemental retirement plans. At December 31, 2012 and 2011, trust assets of

$48 and $51, respectively, were invested primarily in interest-earning accounts.

Employee Incentive Plans The Chevron Incentive Plan is an annual cash bonus

plan for eligible employees that links awards to corporate, unit and individual

performance in the prior year. Charges to expense for cash bonuses were $898,

$1,217 and $766 in 2012, 2011 and 2010, respectively. Chevron also has the LTIP

for officers and other regular salaried employees of the company and its subsidiaries

who hold positions of significant responsibility. Awards under the LTIP consist of

stock options and other share-based compensation that are described in Note 19,

beginning on page FS-48.

Note 21

Equity

Retained earnings at December 31, 2012 and 2011, included approximately $10,119

and $10,127, respectively, for the company’s share of undistributed earnings of

equity affiliates.

 At December 31, 2012, about 55 million shares of Chevron’s common stock

remained available for issuance from the 160 million shares that were reserved for

issuance under the Chevron LTIP. In addition, approximately 231,000 shares remain

available for issuance from the 800,000 shares of the company’s common stock that

were reserved for awards under the Chevron Corporation Non-Employee Directors’

Equity Compensation and Deferral Plan.

Note 22

Other Contingencies and Commitments

Income Taxes The company calculates its income tax expense and liabilities

quarterly. These liabilities generally are subject to audit and are not finalized with the

individual taxing authorities until several years after the end of the annual period for

which income taxes have been calculated. Refer to Note 14, beginning on page FS43, for a discussion of the periods for which tax returns have been audited for the

company’s major tax jurisdictions and a discussion for all tax jurisdictions of the

differences between the amount of tax benefits recognized in the financial statements

and the amount taken or expected to be taken in a tax return. As discussed on page

FS-45, Chevron is currently assessing the potential impact of a decision by the U.S.

Court of Appeals for the Third Circuit that disallows the Historic RehabilitaFS-55
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 Note 22 Other Contingencies and Commitments - Continued

tion Tax Credits claimed by an unrelated taxpayer. It is reasonably possible that the

specific findings from this assessment could result in a significant increase in

unrecognized tax benefits, which may have a material effect on the company's results

of operations in any one reporting period. The company does not expect settlement of

income tax liabilities associated with uncertain tax positions to have a material effect on

its consolidated financial position or liquidity.

Guarantees The company’s guarantee of $562 is associated with certain payments

under a terminal use agreement entered into by an equity affiliate. Over the

approximate 15-year remaining term of the guarantee, the maximum guarantee

amount will be reduced over time as certain fees are paid by the affiliate. There are

numerous cross-indemnity agreements with the affiliate and the other partners to

permit recovery of amounts paid under the guarantee. Chevron has recorded no

liability for its obligation under this guarantee.

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 2012, the company paid $48 under these indemnities and continues to be

obligated up to $250 for possible additional indemnification payments in the future.

 The company has also provided indemnities relating to contingent environmental

liabilities of 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 February 2012 for Motiva indemnities. In February 2012,

Motiva Enterprises LLC delivered a letter to the company purporting to preserve

unmatured claims for certain Motiva indemnities. The company had previously

provided a negative response to similar claims. The letter itself provides no estimate of

the ultimate claim amount. Management does not believe this letter or any other

information provides a basis to estimate the amount, if any, of a range of loss or

potential range of loss with respect to either the Equilon or the Motiva indemnities.

The company posts no assets as collateral and has made no payments under the

indemnities.

Through December 31, 2012, the company has not received further correspondence

from Equilon and Motiva Enterprises LLC and the company does not expect further

action to occur related to the indemnities described in the preceding paragraphs.

 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, which had been reached at December 31, 2009. Under

the indemnification agreement, after reaching the $200 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.

Long-Term Unconditional Purchase Obligations and Commitments,

Including Throughput and Take-or-Pay Agreements The company and its

subsidiaries have certain other contingent liabilities with respect to long-term

unconditional purchase obligations and commitments, including throughput and takeor-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. The aggregate approximate amounts of

required payments under these various commitments are: 2013 – $3,700; 2014 –

$3,900; 2015 – $4,100; 2016 – $2,400; 2017 – $1,800; 2018 and after –

$6,500. A portion of these commitments may ultimately be shared with project

partners. Total payments under the agreements were approximately $3,600 in 2012,

$6,600 in 2011 and $6,500 in 2010.

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,

FS-56
 Note 22 Other Contingencies and Commitments - Continued

the determination of the company’s liability in proportion to other responsible parties,

and the extent to which such costs are recoverable from third parties.

 Although the company has provided for known environmental obligations that are

probable and reasonably estimable, the amount of additional future costs may be

material to results of operations in the period in which they are recognized. The

company does not expect these costs will have a material effect on its consolidated

financial position or liquidity. Also, the company does not believe its obligations to

make such expenditures have had, or will have, any significant impact on the

company’s competitive position relative to other U.S. or international petroleum or

chemical companies.

 Chevron’s environmental reserve as of December 31, 2012, was $1,403.

Included in this balance were remediation activities at approximately 175 sites for

which the company had been identified as a potentially responsible party or otherwise

involved in the remediation by the U.S. Environmental Protection Agency (EPA) or

other regulatory agencies under the provisions of the federal Superfund law or

analogous state laws. The company’s remediation reserve for these sites at year-end

2012 was $157. The federal Superfund law and analogous state laws provide for

joint and several liability for all responsible parties. Any future actions by the EPA or

other regulatory agencies to require Chevron to assume other potentially responsible

parties’ costs at designated hazardous waste sites are not expected to have a material

effect on the company’s results of operations, consolidated financial position or

liquidity.

 Of the remaining year-end 2012 environmental reserves balance of $1,246, $782

related to the company’s U.S. downstream operations, including refineries and other

plants, marketing locations (i.e., service stations and terminals), chemical facilities,

and pipelines. The remaining $464 was associated with various sites in international

downstream $93, upstream $309 and other businesses $62. Liabilities at all sites,

whether operating, closed or divested, were primarily associated with the company’s

plans and activities to remediate soil or groundwater contamination or both. These

and other activities include one or more of the following: site assessment; soil

excavation; offsite disposal of contaminants; onsite containment, remediation and/or

extraction of petroleum hydrocarbon liquid and vapor from soil; groundwater

extraction and treatment; and monitoring of the natural attenuation of the

contaminants.

 The company manages environmental liabilities under specific sets of regulatory

requirements, which in the United States include the Resource Conservation and

Recovery Act and various state and local regulations. No single remediation site at

year-end 2012 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.

 It is likely that the company will continue to incur additional liabilities, beyond

those recorded, for environmental remediation relating to past operations. 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.

 Refer to Note 23 on page FS-58 for a discussion of the company’s asset

retirement obligations.

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.

 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.

FS-57
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 

Note 23

Asset Retirement Obligations

The company records the fair value of a liability for an asset retirement obligation

(ARO) as an asset and liability when there is a legal obligation associated with the

retirement of a tangible long-lived asset and the liability can be reasonably estimated.

The legal obligation to perform the asset retirement activity is unconditional, even

though uncertainty may exist about the timing and/or method of settlement that may

be beyond the company’s control. This uncertainty about the timing and/or method

of settlement is factored into the measurement of the liability when sufficient

information exists to reasonably estimate fair value. Recognition of the ARO includes:

(1) the present value of a liability and offsetting asset, (2) the subsequent accretion of

that liability and depreciation of the asset, and (3) the periodic review of the ARO

liability estimates and discount rates.

 AROs are primarily recorded for the company’s crude oil and natural gas

producing assets. No significant AROs associated with any legal obligations to retire

downstream long-lived assets have been recognized, as indeterminate settlement dates

for the asset retirements prevent estimation of the fair value of the associated ARO.

The company performs periodic reviews of its downstream long-lived assets for any

changes in facts and circumstances that might require recognition of a retirement

obligation.

 The following table indicates the changes to the company’s before-tax asset

retirement obligations in 2012, 2011 and 2010:

2012 2011 2010

Balance at January 1 $ 12,767 $ 12,488 $ 10,175

Liabilities incurred 133 62 129

Liabilities settled (966) (1,316) (755)

Accretion expense 629 628 513

Revisions in estimated cash flows 708 905 2,426

Balance at December 31 $ 13,271 $ 12,767 $ 12,488

 The long-term portion of the $13,271 balance at the end of 2012 was $12,375.

Note 24

Other Financial Information

Earnings in 2012 included gains of approximately $2,800 relating to the sale of

nonstrategic properties. Of this amount, approximately $2,200 and $600 related to

upstream and downstream assets, respectively. Earnings in 2011 included gains of

approximately $1,300 relating to the sale of nonstrategic properties. Of this amount,

approximately $800 and $500 related to downstream and upstream assets,

respectively.

 Other financial information is as follows:

Year ended December 31

2012 2011 2010

Total financing interest and debt costs $ 242 $ 288 $ 317

Less: Capitalized interest 242 288 267

Interest and debt expense $ — $ — $ 50

Research and development expenses $ 648 $ 627 $ 526

Foreign currency effects* $ (454) $ 121 $ (423)

* Includes $(202), $(27) and $(71) in 2012, 2011 and 2010, respectively, for the

company’s share of equity affiliates’ foreign currency effects.

 The excess of replacement cost over the carrying value of inventories for which

the last-in, first-out (LIFO) method is used was $9,292 and $9,025 at

December 31, 2012 and 2011, respectively. Replacement cost is generally based on

average acquisition costs for the year. LIFO profits (charges) of $121, $193 and $21

were included in earnings for the years 2012, 2011 and 2010, respectively.

 The company has $4,640 in goodwill on the Consolidated Balance Sheet related

to the 2005 acquisition of Unocal and to the 2011 acquisition of Atlas Energy, Inc.

Under the accounting standard for goodwill (ASC 350), the company tested this

goodwill for impairment during 2012 and concluded no impairment was necessary.

FS-58
Note 25

Earnings Per Share

Basic earnings per share (EPS) is based upon “Net Income Attributable to Chevron

Corporation” (“earnings”) and includes the effects of deferrals of salary and other

compensation awards that are invested in Chevron stock units by certain officers and

employees of the company. Diluted EPS includes the effects of these items as well as

the dilutive effects of outstanding stock options awarded under the company’s stock

option programs (refer to Note 19, “Stock Options and Other Share-Based

Compensation,” beginning on page FS-48). The table below sets forth the

computation of basic and diluted EPS:

Year ended December 31

2012 2011 2010

Basic EPS Calculation

Earnings available to common stockholders - Basic* $ 26,179 $ 26,895 $ 19,024

Weighted-average number of common shares outstanding 1,950 1,986 1,996

 Add: Deferred awards held as stock units — — 1

Total weighted-average number of common shares outstanding 1,950 1,986 1,997

Earnings per share of common stock - Basic $ 13.42 $ 13.54 $ 9.53

Diluted EPS Calculation

Earnings available to common stockholders - Diluted* $ 26,179 $ 26,895 $ 19,024

Weighted-average number of common shares outstanding 1,950 1,986 1,996

 Add: Deferred awards held as stock units — — 1

 Add: Dilutive effect of employee stock-based awards 15 15 10

Total weighted-average number of common shares outstanding 1,965 2,001 2,007

Earnings per share of common stock - Diluted $ 13.32 $ 13.44 $ 9.48

* There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings.

FS-59
Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

 

Note 26

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

$4,500, which included $3,009 cash for all the common shares of Atlas, a $403

cash advance to facilitate Atlas' purchase of a 49 percent interest in Laurel Mountain

Midstream LLC and about $1,100 of assumed debt. Subsequent to the close of the

transaction, the company paid off the assumed debt and made payments of $184 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 $1,300.

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

first quarter 2011 for acquired assets and assumed liabilities, and the measurement

process was finalized in fourth quarter 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 measurement of the assets acquired and liabilities

assumed:

At February 17, 2011

Current assets $ 155

Investments and long-term receivables 456

Properties 6,051

Goodwill 27

Other assets 5

Total assets acquired 6,694

Current liabilities (560)

Long-term debt and capital leases (761)

Deferred income taxes (1,915)

Other liabilities (25)

Total liabilities assumed (3,261)

Net assets acquired $ 3,433

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. Refer to Note 8, beginning on

page FS-33 for a definition of fair value hierarchy levels. 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 $3,400 in cash.

The $27 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).

FS-60
Five-Year Financial Summary

Unaudited

Millions of dollars, except per-share amounts 2012 2011 2010 2009 2008

Statement of Income Data

Revenues and Other Income

Total sales and other operating revenues* $ 230,590 $ 244,371 $ 198,198 $ 167,402 $ 264,958

Income from equity affiliates and other income 11,319 9,335 6,730 4,234 8,047

Total Revenues and Other Income 241,909 253,706 204,928 171,636 273,005

Total Costs and Other Deductions 195,577 206,072 172,873 153,108 229,948

Income Before Income Tax Expense 46,332 47,634 32,055 18,528 43,057

Income Tax Expense 19,996 20,626 12,919 7,965 19,026

Net Income 26,336 27,008 19,136 10,563 24,031

Less: Net income attributable to noncontrolling interests 157 113 112 80 100

Net Income Attributable to Chevron Corporation $ 26,179 $ 26,895 $ 19,024 $ 10,483 $ 23,931

Per Share of Common Stock

Net Income Attributable to Chevron

– Basic $ 13.42 $ 13.54 $ 9.53 $ 5.26 $ 11.74

– Diluted $ 13.32 $ 13.44 $ 9.48 $ 5.24 $ 11.67

Cash Dividends Per Share $ 3.51 $ 3.09 $ 2.84 $ 2.66 $ 2.53

Balance Sheet Data (at December 31)

Current assets $ 55,720 $ 53,234 $ 48,841 $ 37,216 $ 36,470

Noncurrent assets 177,262 156,240 135,928 127,405 124,695

Total Assets 232,982 209,474 184,769 164,621 161,165

Short-term debt 127 340 187 384 2,818

Other current liabilities 34,085 33,260 28,825 25,827 29,205

Long-term debt and capital lease obligations 12,065 9,812 11,289 10,130 6,083

Other noncurrent liabilities 48,873 43,881 38,657 35,719 35,942

Total Liabilities 95,150 87,293 78,958 72,060 74,048

Total Chevron Corporation Stockholders' Equity $ 136,524 $ 121,382 $ 105,081 $ 91,914 $ 86,648

 Noncontrolling interests 1,308 799 730 647 469

Total Equity $ 137,832 $ 122,181 $ 105,811 $ 92,561 $ 87,117

* Includes excise, value-added and similar taxes: $ 8,010 $ 8,085 $ 8,591 $ 8,109 $ 9,846

FS-61
 Supplemental Information on Oil and Gas Producing Activities

 Unaudited

In accordance with FASB and SEC disclosure and reporting requirements for oil and

gas producing activities, this section provides supplemental information on oil and gas

exploration and producing activities of the company in seven separate

tables. Tables I through IV provide historical cost information pertaining to costs

incurred in exploration, property acquisitions and development; capitalized costs; and

results of operations. Tables V through VII present information

Table I - Costs Incurred in Exploration, Property Acquisitions and Development 1

Consolidated Companies Affiliated Companies

Other

Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other

Year Ended December 31, 2012

Exploration

Wells $ 251 $ 202 $ 121 $ 271 $ 302 $ 88 $ 1,235 $ — $ —

Geological and geophysical 99 105 107 86 47 58 502 — —

Rentals and other 161 55 93 201 85 107 702 — —

Total exploration 511 362 321 558 434 253 2,439 — —

Property acquisitions2

Proved 248 — 8 39 — — 295 — —

Unproved 1,150 29 5 342 28 — 1,554 — 28

Total property acquisitions 1,398 29 13 381 28 — 1,849 — 28

Development3 6,597 1,211 3,118 3,797 4,555 753 20,031 660 293

Total Costs Incurred4 $ 8,506 $ 1,602 $ 3,452 $ 4,736 $ 5,017 $ 1,006 $ 24,319 $ 660 $ 321

Year Ended December 31, 2011

Exploration

Wells $ 321 $ 71 $ 104 $ 146 $ 242 $ 188 $ 1,072 $ — $ —

Geological and geophysical 76 59 65 121 23 43 387 — —

Rentals and other 109 45 83 67 71 78 453 — —

Total exploration 506 175 252 334 336 309 1,912 — —

Property acquisitions2

Proved 1,174 16 — 1 — — 1,191 — —

Unproved 7,404 228 — — — 25 7,657 — —

Total property acquisitions 8,578 244 — 1 — 25 8,848 — —

Development3 5,517 1,537 2,698 2,867 2,638 633 15,890 379 368

Total Costs Incurred4 $ 14,601 $ 1,956 $ 2,950 $ 3,202 $ 2,974 $ 967 $ 26,650 $ 379 $ 368

Year Ended December 31, 2010

Exploration

Wells $ 99 $ 118 $ 94 $ 244 $ 293 $ 61 $ 909 $ — $ —

Geological and geophysical 67 46 87 29 8 18 255 — —

Rentals and other 121 39 55 47 95 57 414 — —

Total exploration 287 203 236 320 396 136 1,578 — —

Property acquisitions2

Proved 24 — — 129 — — 153 — —

Unproved 359 429 160 187 — 10 1,145 — —

Total property acquisitions 383 429 160 316 — 10 1,298 — —

Development3 4,446 1,611 2,985 3,325 2,623 411 15,401 230 343

Total Costs Incurred $ 5,116 $ 2,243 $ 3,381 $ 3,961 $ 3,019 $ 557 $ 18,277 $ 230 $ 343

1 Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 23, “Asset Retirement

Obligations,” on page FS-58.

2 Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired in nonmonetary transactions, such as $1,850 million related to the 2012 acquisition of Clio and Acme fields in

Australia.

3 Includes $963, $1,035 and $745 costs incurred prior to assignment of proved reserves for consolidated companies in 2012, 2011 and 2010, respectively.

4 Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures - $ billions.

Total cost incurred for 2012

$ 25.3

 Non oil and gas activities 5.8 (Includes LNG and gas-to-liquids $4.6, transportation $0.6, affiliate $0.4, other $0.2)

 ARO (0.7)

Upstream C&E $ 30.4 Reference Page FS-12 upstream total
FS-62
 Table I Costs Incurred in Exploration, Property Acquisitions and Development

on the company’s estimated net proved-reserve quantities, standardized measure of

estimated discounted future net cash flows related to proved reserves and changes in

estimated discounted future net cash flows. The Africa geographic area includes

activities principally in Angola, Chad, Democratic Republic of the Congo, Nigeria and

Republic of the Congo. The Asia geographic area includes activities principally in

Azerbaijan, Bangladesh, China, Indonesia, Kazakhstan, Myanmar, the Partitioned

Zone between Kuwait and Saudi Arabia, the Philippines, and Thailand. The Europe

geographic area includes activity in Denmark, the

Netherlands, Norway and the United Kingdom. The Other Americas geographic

region includes activities in Argentina, Brazil, Canada, Colombia, and Trinidad and

Tobago. Amounts for TCO represent Chevron’s 50 percent equity share of

Tengizchevroil, an exploration and production partnership in the Republic of

Kazakhstan. The affiliated companies Other amounts are composed of the company’s

equity interests in Venezuela and Angola. Refer to Note 11, beginning on page FS38, for a discussion of the company’s major equity affiliates.

Table II - Capitalized Costs Related to Oil and Gas Producing Activities

Consolidated Companies Affiliated Companies

Other

Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other

At December 31, 2012

Unproved properties $ 10,478 $ 1,415 $ 271 $ 2,039 $ 1,884 $ 34 $ 16,121 $ 109 $ 28

Proved properties and 

related producing assets 62,274 11,237 30,106 39,889 2,420 9,994 155,920 6,832 1,852

Support equipment 1,179 330 1,195 1,554 1,191 172 5,621 1,089 —

Deferred exploratory wells 412 201 598 326 911 233 2,681 — —

Other uncompleted projects 7,203 3,211 3,466 4,123 9,754 768 28,525 906 1,594

Gross Capitalized Costs 81,546 16,394 35,636 47,931 16,160 11,201 208,868 8,936 3,474

Unproved properties valuation 1,121 634 201 253 2 28 2,239 41 —

Proved producing properties – Depreciation and

depletion 42,224 5,288 15,566 24,432 1,832 8,255 97,597 2,274 551

Support equipment depreciation 589 178 613 1,101 305 137 2,923 480 —

Accumulated provisions 43,934 6,100 16,380 25,786 2,139 8,420 102,759 2,795 551

Net Capitalized Costs $ 37,612 $ 10,294 $ 19,256 $ 22,145 $ 14,021 $ 2,781 $106,109 $ 6,141 $ 2,923

At December 31, 2011

Unproved properties $ 9,806 $ 1,417 $ 368 $ 2,408 $ 6 $ 33 $ 14,038 $ 109 $ —

Proved properties and 

related producing assets 57,674 11,029 25,549 36,740 2,244 9,549 142,785 6,583 1,607

Support equipment 1,071 292 1,362 1,544 533 169 4,971 1,018 —

Deferred exploratory wells 565 63 629 260 709 208 2,434 — —

Other uncompleted projects 4,887 2,408 4,773 3,109 6,076 492 21,745 605 1,466

Gross Capitalized Costs 74,003 15,209 32,681 44,061 9,568 10,451 185,973 8,315 3,073

Unproved properties valuation 1,085 498 178 262 2 13 2,038 38 —

Proved producing properties – Depreciation and

depletion 39,210 4,826 13,173 20,991 1,574 7,742 87,516 1,910 436

Support equipment depreciation 530 175 715 1,192 238 129 2,979 451 —

Accumulated provisions 40,825 5,499 14,066 22,445 1,814 7,884 92,533 2,399 436

Net Capitalized Costs $ 33,178 $ 9,710 $ 18,615 $ 21,616 $ 7,754 $ 2,567 $ 93,440 $ 5,916 $ 2,637

FS-63
 Table II Capitalized Costs Related to Oil and 

 Gas Producing Activities - Continued

Consolidated Companies Affiliated Companies

Other

Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other

At December 31, 2010

Unproved properties $ 2,553 $ 1,349 $ 359 $ 2,561 $ 6 $ 8 $ 6,836 $ 108 $ —

Proved properties and 

related producing assets 55,601 7,747 23,683 33,316 2,585 9,035 131,967 6,512 1,594

Support equipment 975 265 1,282 1,421 259 165 4,367 985 —

Deferred exploratory wells 743 210 611 224 732 198 2,718 — —

Other uncompleted projects 2,299 3,844 4,061 3,627 3,631 362 17,824 357 1,001

Gross Capitalized Costs 62,171 13,415 29,996 41,149 7,213 9,768 163,712 7,962 2,595

Unproved properties valuation 967 436 150 200 2 — 1,755 34 —

Proved producing properties – Depreciation and

depletion 37,682 3,986 10,986 18,197 1,718 7,162 79,731 1,530 249

Support equipment depreciation 518 153 600 1,126 84 114 2,595 402 —

Accumulated provisions 39,167 4,575 11,736 19,523 1,804 7,276 84,081 1,966 249

Net Capitalized Costs $ 23,004 $ 8,840 $ 18,260 $ 21,626 $ 5,409 $ 2,492 $ 79,631 $ 5,996 $ 2,346

FS-64
 Table III Results of Operations for Oil and 

 Gas Producing Activities1

 The company’s results of operations from oil and gas producing activities for the

years 2012, 2011 and 2010 are shown in the following table. Net income from

exploration and production activities as reported on page FS-37 reflects income taxes

computed on an effective rate basis.

Income taxes in Table III are based on statutory tax rates, reflecting allowable

deductions and tax credits. Interest income and expense are excluded from the results

reported in Table III and from the net income amounts on page FS-37.

Table III - Results of Operations for Oil and Gas Producing Activities 1

Consolidated Companies Affiliated Companies

Other

Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other

Year Ended December 31, 2012

Revenues from net production

Sales $ 1,832 $ 1,561 $ 1,480 $ 10,485 $ 1,539 $ 1,618 $ 18,515 $ 7,869 $ 1,951

Transfers 15,122 1,997 15,033 9,071 1,073 2,148 44,444 — —

Total 16,954 3,558 16,513 19,556 2,612 3,766 62,959 7,869 1,951

Production expenses excluding taxes (4,009) (1,073) (1,918) (4,545) (164) (637) (12,346) (463) (442)

Taxes other than on income (654) (123) (161) (191) (390) (3) (1,522) (439) (767)

Proved producing properties:

Depreciation and depletion (3,462) (508) (2,475) (3,399) (315) (541) (10,700) (427) (147)

Accretion expense2 (226) (33) (66) (92) (23) (46) (486) (8) (6)

Exploration expenses (244) (145) (427) (489) (133) (272) (1,710) — —

Unproved properties valuation (127) (138) (16) (133) — (15) (429) — —

Other income (expense)3 167 (169) (199) 245 2,495 13 2,552 27 31

Results before income taxes 8,399 1,369 11,251 10,952 4,082 2,265 38,318 6,559 620

Income tax expense (3,043) (310) (7,558) (5,739) (1,226) (1,511) (19,387) (1,972) (299)

Results of Producing Operations $ 5,356 $ 1,059 $ 3,693 $ 5,213 $ 2,856 $ 754 $ 18,931 $ 4,587 $ 321

Year Ended December 31, 2011 4

Revenues from net production

Sales $ 2,508 $ 2,047 $ 1,174 $ 9,431 $ 1,474 $ 1,868 $ 18,502 $ 8,581 $ 1,988

Transfers 15,811 2,624 15,726 8,962 1,012 2,672 46,807 — —

Total 18,319 4,671 16,900 18,393 2,486 4,540 65,309 8,581 1,988

Production expenses excluding taxes (3,668) (1,061) (1,526) (4,489) (117) (564) (11,425) (449) (235)

Taxes other than on income (597) (137) (153) (242) (396) (2) (1,527) (429) (815)

Proved producing properties:

Depreciation and depletion (3,366) (796) (2,225) (2,923) (136) (580) (10,026) (442) (140)

Accretion expense2(291) (27) (106) (81) (18) (39) (562) (8) (4)

Exploration expenses (207) (144) (188) (271) (128) (277) (1,215) — —

Unproved properties valuation (134) (146) (27) (60) — (14) (381) — —

Other income (expense)3 163 (466) (409) 231 (18) (74) (573) (8) (29)

Results before income taxes 10,219 1,894 12,266 10,558 1,673 2,990 39,600 7,245 765

Income tax expense (3,728) (535) (7,802) (5,374) (507) (1,913) (19,859) (2,176) (392)

Results of Producing Operations $ 6,491 $ 1,359 $ 4,464 $ 5,184 $ 1,166 $ 1,077 $ 19,741 $ 5,069 $ 373

1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net

production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.

2 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page FS-58.

3 Includes foreign currency gains and losses, gains and losses on property dispositions (primarily related to Browse and Wheatstone gains in 2012), and other miscellaneous income and

expenses.

4 2011 and 2010 conformed to 2012 presentation.

FS-65
 Table III Results of Operations for Oil and 

 Gas Producing Activities - Continued

Consolidated Companies Affiliated Companies

Other

Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other

Year Ended December 31, 2010 4

Revenues from net production

Sales $ 2,540 $ 1,881 $ 2,278 $ 7,221 $ 994 $ 1,519 $ 16,433 $ 6,031 $ 1,307

Transfers 12,172 1,147 10,306 6,242 985 2,138 32,990 — —

Total 14,712 3,028 12,584 13,463 1,979 3,657 49,423 6,031 1,307

Production expenses excluding taxes (3,338) (805) (1,413) (2,996) (96) (534) (9,182) (347) (152)

Taxes other than on income (542) (102) (130) (85) (334) (2) (1,195) (360) (101)

Proved producing properties:

Depreciation and depletion (3,639) (907) (2,204) (2,816) (151) (681) (10,398) (432) (131)

Accretion expense2(240) (23) (102) (35) (15) (53) (468) (8) (5)

Exploration expenses (193) (173) (242) (289) (175) (75) (1,147) (5) —

Unproved properties valuation (123) (71) (25) (33) — (2) (254) — —

Other income (expense)3(154) (367) (103) (282) 109 165 (632) (65) 191

Results before income taxes 6,483 580 8,365 6,927 1,317 2,475 26,147 4,814 1,109

Income tax expense (2,273) (223) (4,535) (3,886) (325) (1,455) (12,697) (1,445) (615)

Results of Producing Operations $ 4,210 $ 357 $ 3,830 $ 3,041 $ 992 $ 1,020 $ 13,450 $ 3,369 $ 494

1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales

price and production cost. This has no effect on the results of producing operations.

2 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page FS-58.

3

Includes foreign currency gains and losses, gains and losses on property dispositions, and other miscellaneous income and expenses.

4 2011 and 2010 conformed to 2012 presentation.

FS-66
 Table IV Results of Operations for Oil and 

 Gas Producing Activities - Unit Prices and Costs 1

Consolidated Companies Affiliated Companies

Other

U.S. Americas Africa Asia Australia Europe Total TCO Other

Year Ended December 31, 2012

Average sales prices

Liquids, per barrel $ 95.21 $ 87.87 $ 109.64 $ 102.46 $ 103.06 $ 108.77 $ 101.61 $ 89.34 $ 83.97

Natural gas, per thousand cubic feet 2.65 3.59 1.22 6.03 10.99 10.10 5.42 1.36 5.39

Average production costs, per barrel2 16.99 18.38 12.14 16.71 4.86 15.72 15.46 4.42 18.73

Year Ended December 31, 2011 3

Average sales prices

Liquids, per barrel $ 97.51 $ 89.87 $ 109.45 $ 100.55 $ 103.70 $ 107.11 $ 101.63 $ 94.60 $ 90.90

Natural gas, per thousand cubic feet 4.02 2.97 0.41 5.28 9.98 9.91 5.29 1.60 6.57

Average production costs, per barrel2 15.08 14.62 9.48 17.47 3.41 11.44 13.98 4.23 10.54

Year Ended December 31, 2010 3

Average sales prices

Liquids, per barrel $ 71.59 $ 66.22 $ 78.00 $ 70.96 $ 76.43 $ 76.10 $ 73.24 $ 63.94 $ 64.92

Natural gas, per thousand cubic feet 4.25 2.52 0.73 4.45 6.76 7.09 4.55 1.41 4.20

Average production costs, per barrel2 13.11 11.86 8.57 11.71 2.55 9.42 10.96 3.14 7.37

1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales

price and production cost. This has no effect on the results of producing operations.

2 Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.

3 2011 and 2010 conformed to 2012 presentation.

Table V Reserve Quantity Information

Reserves Governance The company has adopted a comprehensive reserves and

resource classification system modeled after a system developed and approved by the

Society of Petroleum Engineers, the World Petroleum Congress and the American

Association of Petroleum Geologists. The system classifies recoverable hydrocarbons

into six categories based on their status at the time of reporting – three deemed

commercial and three potentially recoverable. Within the commercial classification are

proved reserves and two categories of unproved: probable and possible. The

potentially recoverable categories are also referred to as contingent resources. For

reserves estimates to be classified as proved, they must meet all SEC and company

standards.

 Proved oil and gas reserves are the estimated quantities that geoscience and

engineering data demonstrate with reasonable certainty to be economically producible

in the future from known reservoirs under existing economic conditions, operating

methods and government regulations. Net proved reserves exclude royalties and

interests owned by others and reflect contractual arrangements and royalty obligations

in effect at the time of the estimate.

 Proved reserves are classified as either developed or undeveloped. Proved

developed reserves are the quantities expected to be recovered through existing wells

with existing equipment and operating methods.

 Due to the inherent uncertainties and the limited nature of reservoir data,

estimates of reserves are subject to change as additional information becomes

available.

 Proved reserves are estimated by company asset teams

composed of earth scientists and engineers. As part of the

internal control process related to reserves estimation, the company maintains a

Reserves Advisory Committee (RAC) that is chaired by the Manager of Corporate

Reserves, a corporate department that reports directly to the Vice Chairman

responsible for the company’s worldwide exploration and production activities. The

Manager of Corporate Reserves has more than 30 years’ experience working in the

oil and gas industry and a Master of Science in Petroleum Engineering degree from

Stanford University. His experience includes more than 15 years of managing oil and

gas reserves processes. He was chairman of the Society of Petroleum Engineers Oil

and Gas Reserves Committee, served on the United Nations Expert Group on

Resources Classification, and is a past member of the Joint Committee on Reserves

Evaluator Training and the California Conservation Committee. He is an active

member of the Society of Petroleum Evaluation Engineers and serves on the Society

of Petroleum Engineers Oil and Gas Reserves Committee.

 All RAC members are degreed professionals, each with more than 15 years of

experience in various aspects of reserves estimation relating to reservoir engineering,

petroleum engineering, earth science or finance. The members are knowledgeable in

SEC guidelines for proved reserves classification and receive annual training on the

preparation of reserves estimates. The reserves activities are managed by two

operating company-level reserves managers. These two reserves managers are not

members of the RAC so as to preserve corporate-level independence.

FS-67
 Table V Reserve Quantity Information - Continued

Summary of Net Oil and Gas Reserves

2012* 2011* 2010*

Liquids in Millions of Barrels

Crude Oil Crude Oil Crude Oil

Condensate Synthetic Natural Condensate Synthetic Natural Condensate Synthetic Natural

Natural Gas in Billions of Cubic Feet NGLs Oil Gas NGLs Oil Gas NGLs Oil Gas

Proved Developed

 Consolidated Companies

 U.S. 1,012 — 2,574 990 — 2,486 1,045 — 2,113

 Other Americas 91 391 1,063 82 403 1,147 84 352 1,490

 Africa 782 — 1,163 792 — 1,276 830 — 1,304

 Asia 643 — 4,511 703 — 4,300 826 — 4,836

 Australia 31 — 682 39 — 813 39 — 881

 Europe 103 — 191 116 — 204 136 — 235

 Total Consolidated 2,662 391 10,184 2,722 403 10,226 2,960 352 10,859

 Affiliated Companies

 TCO 977 — 1,261 1,019 — 1,400 1,128 — 1,484

 Other 115 50 377 93 50 75 95 53 70

 Total Consolidated and Affiliated Companies 3,754 441 11,822 3,834 453 11,701 4,183 405 12,413

Proved Undeveloped

 Consolidated Companies

 U.S. 347 — 1,148 321 — 1,160 230 — 359

 Other Americas 132 122 412 31 120 517 24 114 325

 Africa 348 — 1,918 363 — 1,920 338 — 1,640

 Asia 194 — 2,356 191 — 2,421 187 — 2,357

 Australia 103 — 9,570 101 — 8,931 49 — 5,175

 Europe 54 — 66 43 — 54 16 — 40

 Total Consolidated 1,178 122 15,470 1,050 120 15,003 844 114 9,896

 Affiliated Companies

 TCO 755 — 1,038 740 — 851 692 — 902

 Other 49 182 865 64 194 1,128 62 203 1,040

 Total Consolidated and Affiliated Companies 1,982 304 17,373 1,854 314 16,982 1,598 317 11,838

Total Proved Reserves 5,736 745 29,195 5,688 767 28,683 5,781 722 24,251

* Based on 12-month average price.

The RAC has the following primary responsibilities: establish the policies and

processes used within the operating units to estimate reserves; provide independent

reviews and oversight of the business units’ recommended reserves estimates and

changes; confirm that proved reserves are recognized in accordance with SEC

guidelines; determine that reserve volumes are calculated using consistent and

appropriate standards, procedures and technology; and maintain the Corporate

Reserves Manual, which provides standardized procedures used corporatewide for

classifying and reporting hydrocarbon reserves.

 During the year, the RAC is represented in meetings with each of the company’s

upstream business units to review and discuss reserve changes recommended by the

various asset teams. Major changes are also reviewed with the company’s Strategy

and Planning Committee, whose members include the Chief Executive Officer and the

Chief Financial Officer. The company’s annual reserve activity is also reviewed with

the Board of Directors. If major changes to reserves were to occur between the

annual reviews, those matters would also be discussed with the Board.

 RAC subteams also conduct in-depth reviews during the year of many of the

fields that have large proved reserves quantities. These reviews include an

examination of the proved-reserve records and documentation of their compliance

with the Corporate Reserves Manual.

 Technologies Used in Establishing Proved Reserves Additions In 2012,

additions to Chevron’s proved reserves were based on a wide range of geologic and

engineering technologies. Information generated from wells, such as well logs, wire

line sampling, production and pressure testing, fluid analysis, and core analysis, was

integrated with seismic data, regional geologic studies, and information from

analogous reservoirs to provide “reasonably certain” proved reserves estimates. Both

proprietary and commercially available analytic tools, including reservoir simulation,

geologic modeling and seismic processing, have been used in the interpretation of the

subsurface data. These technologies have been utilized extensively by the company in

the past, and the company believes that they provide a high degree of confidence in

establishing reliable and consistent reserves estimates.

FS-68
 Table V Reserve Quantity Information - Continued

 Proved Undeveloped Reserve Quantities At the end of 2012, proved

undeveloped reserves totaled 5.2 billion barrels of oil-equivalent (BOE).

Approximately 56 percent of these reserves are attributed to natural gas, of which

about 55 percent were located in Australia. Crude oil, condensate and natural gas

liquids (NGLs) accounted for about 38 percent of the total proved undeveloped

reserves, of which about 38 percent were from TCO, and the remaining large

concentrations were in Africa, Asia and the United States. Synthetic oil accounted for

the balance of the proved undeveloped reserves.

 In 2012, a total of 394 million BOE was transferred from proved undeveloped to

proved developed. In Asia, 98 million BOE were transferred to proved developed

primarily driven by development drilling performance. In the United States,

approximately 95 million BOE were transferred, primarily due to ongoing drilling

activities in the deepwater Gulf of Mexico and California. Affiliates accounted for 104

million BOE transferred to proved developed due to ongoing development activities.

Development drilling and the start up of several projects in Africa, Europe and Other

Americas accounted for the remainder.

 Investment to Convert Proved Undeveloped to Proved Developed

Reserves During 2012, investments totaling approximately $10.7 billion in oil and

gas producing activities and about $3.5 billion in non-oil and gas producing activities

were expended to advance the development of proved undeveloped reserves.

Australia accounted for $7.7 billion of the total, mainly for development and

construction activities at the Gorgon and Wheatstone LNG projects. In Africa,

another $2.3 billion was expended on various offshore development and natural gas

projects in Nigeria and Angola. Expenditures of about $1.8 billion in the United

States related primarily to various development activities in the Gulf of Mexico and

the mid-continent region. In Asia, expenditures during the year totaled $1.7 billion,

primarily related to development projects in Thailand and Indonesia.

 Proved Undeveloped Reserves for Five Years or More Reserves that

remain proved undeveloped for five or more years are a result of several factors that

affect optimal project development and execution, such as the complex nature of the

development project in adverse and remote locations, physical limitations of

infrastructure or plant capacities that dictate project timing, compression projects that

are pending reservoir pressure declines, and contractual limitations that dictate

production levels.

 At year-end 2012, the company held approximately 1.7 billion BOE of proved

undeveloped reserves that have remained undeveloped for five years or more. The

reserves are held by consolidated and affiliated companies and the majority of these

reserves are in locations where the company has a proven track record of developing

major projects.

 In Africa, the majority of the 300 million BOE is related to deepwater and natural

gas developments in Nigeria. Major Nigerian deepwater development projects include

Agbami, which started production in 2008 and has ongoing development activities to

maintain full utilization of infrastructure capacity, and the Usan development, which

started production in 2012. Also in Nigeria, various fields and infrastructure

associated with the Escravos Gas Projects are currently under development.

 In Asia, approximately 200 million BOE remain classified as proved undeveloped

after five years. The majority relate to ongoing development activities in the Pattani

Field (Thailand) and the Malampaya Field (Philippines) that are scheduled to maintain

production within contractual and infrastructure constraints.

 In Australia, approximately 100 million BOE remain classified as proved

undeveloped due to a compression project at the North West Shelf Venture, which is

scheduled for start-up in 2013.

 Affiliated companies have approximately 1.0 billion BOE of proved undeveloped

reserves that have been recorded for five years or more. The TCO affiliate in

Kazakhstan accounts for most of this amount. Production is constrained by plant

capacity limitations. In Venezuela, development drilling continues at Hamaca to

optimize utilization of upgrader capacity.

 Annually, the company assesses whether any changes have occurred in facts or

circumstances, such as changes to development plans, regulations or government

policies, that would warrant a revision to reserve estimates. For 2012, this

assessment did not result in any material changes in reserves classified as proved

undeveloped. Over the past three years, the ratio of proved undeveloped reserves to

total proved reserves has ranged between 37 percent and 46 percent. The consistent

completion of major capital projects has kept the ratio in a narrow range over this

time period.

 Proved Reserve Quantities At December 31, 2012, proved reserves for the

company were 11.3 billion BOE. (Refer to the term “Reserves” on page E-11 for the

definition of oil-equivalent reserves.) Approximately 17 percent of the total reserves

were located in the United States.

Aside from the TCO affiliate's Tengiz Field in Kazakhstan, no single property

accounted for more than 5 percent of the company’s total oil-equivalent proved

reserves. About 20 other individual properties in the company’s portfolio of assets

each contained between 1 percent and 5 percent of the company’s oil-equivalent

proved reserves, which in the aggregate accounted for 45 percent of the company’s

total oil-equivalent proved reserves. These properties were geographically dispersed,

located in the United States, Canada, South America, Africa, Asia and Australia.

FS-69
 Table V Reserve Quantity Information - Continued

In the United States, total proved reserves at year-end 2012 were 2.0 billion BOE.

California properties accounted for 32 percent of the U.S. reserves, with most

classified as heavy oil. Because of heavy oil’s high viscosity and the need to employ

enhanced recovery methods, most of the company’s heavy-oil fields in California

employ a continuous steamflooding process. The Gulf of Mexico region contains

26 percent of the U.S. reserves and production operations are mostly offshore.

Other U.S. areas represent the remaining 42 percent of U.S. reserves. For

production of crude oil, some fields utilize enhanced recovery methods, including

waterflood and CO2 injection.

 For the three years ending December 31, 2012, the pattern of net reserve

changes shown in the following tables are not

necessarily indicative of future trends. Apart from acquisitions, the company’s ability

to add proved reserves is affected by, among other things, events and circumstances

that are outside the company’s control, such as delays in government permitting,

partner approvals of development plans, changes in oil and gas prices, OPEC

constraints, geopolitical uncertainties, and civil unrest.

 The company’s estimated net proved reserves of crude oil, condensate, natural

gas liquids and synthetic oil and changes thereto for the years 2010, 2011 and 2012

are shown in the table below. The company’s estimated net proved reserves of natural

gas are shown on page FS-72.

Net Proved Reserves of Crude Oil, Condensate, Natural Gas Liquids and Synthetic Oil

Consolidated Companies Affiliated Companies

Total

Consolidated

Other Synthetic Synthetic and Affiliated

Millions of barrels U.S. Americas1 Africa Asia Australia Europe Oil2 Total TCO Oil Other3 Companies

Reserves at January 1, 2010 1,361 104 1,246 1,171 98 170 460 4,610 1,946 266 151 6,973

Changes attributable to:

Revisions 63 12 17 (26) 3 19 15 103 (33) — 12 82

Improved recovery 11 3 58 2 — — — 74 — — 3 77

Extensions and discoveries 19 19 9 16 — — — 63 — — — 63

Purchases — — — 11 — — — 11 — — — 11

Sales (1) — — — — — — (1) — — — (1)

Production (178) (30) (162) (161) (13) (37) (9) (590) (93) (10) (9) (702)

Reserves at December 31, 20104 1,275 108 1,168 1,013 88 152 466 4,270 1,820 256 157 6,503

Changes attributable to:

Revisions 63 4 60 25 (2) 15 32 197 28 — 10 235

Improved recovery 6 4 48 — — — — 58 — — — 58

Extensions and discoveries 140 30 34 4 65 26 — 299 — — — 299

Purchases 2 — — — — — 40 42 — — — 42

Sales (5) — — — (1) — — (6) — — — (6)

Production (170) (33) (155) (148) (10) (34) (15) (565) (89) (12) (10) (676)

Reserves at December 31, 20114 1,311 113 1,155 894 140 159 523 4,295 1,759 244 157 6,455

Changes attributable to:

Revisions 104 20 66 97 4 16 6 313 59 (6) 24 390

Improved recovery 24 8 30 6 — 9 — 77 — — — 77

Extensions and discoveries 77 101 30 2 7 — — 217 — — 1 218

Purchases 10 — — — — — — 10 — — — 10

Sales (1) — — (15) (7) — — (23) — — — (23)

Production (166) (19) (151) (147) (10) (27) (16) (536) (86) (6) (18) (646)

Reserves at December 31, 20124 1,359 223 1,130 837 134 157 513 4,353 1,732 232 164 6,481

1 Ending reserve balances in North America were 121, 13 and 14 and in South America were 102, 100 and 94 in 2012, 2011 and 2010, respectively.

2 Reserves associated with Canada.

3 Ending reserve balances in Africa were 41, 3 8 and 36 and in South America were 123, 119 and 121 in 2012, 2011 and 2010, respectively.

4 Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-11 for the definition of a PSC). PSC-related reserve quantities are 20 percent, 22 percent and 24 percent for consolidated

companies for 2012, 2011 and 2010, respectively.

FS-70
 Table V Reserve Quantity Information - Continued

 Noteworthy amounts in the categories of liquids proved reserve changes for 2010

through 2012 are discussed below:

 Revisions In 2010, net revisions increased reserves 82 million barrels. For

consolidated companies, improved reservoir performance accounted for a majority of

the 63 million barrel increase in the United States. Increases in the other regions were

partially offset by Asia, which decreased as a result of the effect of higher prices on

entitlement volumes in Kazakhstan. For affiliated companies, the price effect on

entitlement volumes at TCO decreased reserves by 33 million barrels.

 In 2011, net revisions increased reserves 235 million barrels. For consolidated

companies, improved reservoir performance accounted for a majority of the

63 million barrel increase in the United States. In Africa, improved field performance

drove the 60 million barrel increase. In Asia, increases from improved reservoir

performance were partially offset by the effects of higher prices on entitlement

volumes. Synthetic oil reserves in Canada increased by 32 million barrels, primarily

due to geotechnical revisions. For affiliated companies, improved facility and reservoir

performance was partially offset by the price effect on entitlement volumes at TCO.

In 2012, net revisions increased reserves 390 million barrels. Improved field

performance and drilling associated with Gulf of Mexico projects accounted for the

majority of the 104 million barrel increase in the United States. In Asia, drilling

results across numerous assets drove the 97 million barrel increase. Improved field

performance from various Nigeria and Angola producing assets was primarily

responsible for the 66 million barrel increase in Africa. Improved plant efficiency for

the TCO affiliate was responsible for a large portion of the 59 million barrel

increase. 

Improved Recovery In 2010, improved recovery increased volumes by 77 million

barrels. Reserves in Africa increased 58 million barrels due primarily to secondary

recovery performance in Nigeria.

 In 2011, improved recovery increased volumes by 58 million barrels. Reserves in

Africa increased 48 million barrels due primarily to secondary recovery performance

in Nigeria.

In 2012, improved recovery increased reserves by 77 million barrels, primarily due

to secondary recovery performance in Africa and in Gulf of Mexico fields in the

United States.

 Extensions and Discoveries In 2010, extensions and discoveries increased

reserves 63 million barrels. The United States and Other Americas each increased

reserves 19 million barrels, and Asia increased reserves 16 million barrels. No single

area in the United States was individually significant. Drilling activity in Argentina and

Brazil accounted for the majority of the increase in Other Americas. In Asia, the

increase was primarily related to activity in Azerbaijan.

 In 2011, extensions and discoveries increased reserves 299 million barrels. In the

United States, additions related to two Gulf of Mexico projects resulted in the

majority of the 140 million barrel increase. In Australia, the Wheatstone Project

increased liquid volumes 65 million barrels. Africa and Other Americas increased

reserves 34 million and 30 million barrels, respectively, following the start of new

projects in these areas. In Europe, a project in the United Kingdom increased

reserves 26 million barrels.

In 2012, extensions and discoveries increased reserves 218 million barrels. In Other

Americas, extensions and discoveries increased reserves 101 million barrels primarily

due to the initial booking of the Hebron project in Canada. In the United States,

additions at several Gulf of Mexico projects and drilling activities in the mid-continent

region were primarily responsible for the 77 million barrel increase.

 Purchases In 2011, purchases increased worldwide liquid volumes 42 million

barrels. The acquisition of additional acreage in Canada increased synthetic oil reserves

40 million barrels.

FS-71
 Table V Reserve Quantity Information - Continued

Net Proved Reserves of Natural Gas

Consolidated Companies Affiliated Companies

Total

Consolidated

Other and Affiliated

Billions of cubic feet (BCF) U.S. Americas1 Africa Asia Australia Europe Total TCO Other2 Companies

Reserves at January 1, 2010 2,698 1,985 3,021 7,860 6,245 344 22,153 2,833 1,063 26,049

Changes attributable to:

Revisions 220 4 (20) (31) (22) 46 197 (324) 56 (71)

Improved recovery 1 1 — — — — 2 — — 2

Extensions and discoveries 36 4 — 59 — 11 110 — — 110

Purchases 3 — — 4 — — 7 — — 7

Sales (7) — — — — — (7) — — (7)

Production3 (479) (179) (57) (699) (167) (126) (1,707) (123) (9) (1,839)

Reserves at December 31, 20104 2,472 1,815 2,944 7,193 6,056 275 20,755 2,386 1,110 24,251

Changes attributable to:

Revisions 217 (4) 39 196 (107) 74 415 (21) 103 497

Improved recovery — 1 — — — — 1 — — 1

Extensions and discoveries 287 13 290 46 4,035 9 4,680 — — 4,680

Purchases 1,231 — — 2 — — 1,233 — — 1,233

Sales (95) — — (2) (77) — (174) — — (174)

Production3 (466) (161) (77) (714) (163) (100) (1,681) (114) (10) (1,805)

Reserves at December 31, 20114 3,646 1,664 3,196 6,721 9,744 258 25,229 2,251 1,203 28,683

Changes attributable to:

Revisions 318 (77) (30) 1,007 358 84 1,660 158 37 1,855

Improved recovery 5 — — 1 — 2 8 — — 8

Extensions and discoveries 166 34 2 50 747 — 999 — 12 1,011

Purchases 33 — — — — — 33 — — 33

Sales (6) — — (93) (439) — (538) — — (538)

Production3 (440) (146) (87) (819) (158) (87) (1,737) (110) (10) (1,857)

Reserves at December 31, 20124 3,722 1,475 3,081 6,867 10,252 257 25,654 2,299 1,242 29,195

1 Ending reserve balances in North America and South America were 49, 19, 21 and 1,426, 1,645, 1,794 in 2012, 2011 and 2010, respectively.

2 Ending reserve balances in Africa and South America were 1,068, 1,016, 953 and 174, 187, 157 in 2012, 2011 and 2010, respectively.

3 Total “as sold” volumes are 1,647 BCF, 1,591 BCF and 1,644 BCF for 2012, 2011 and 2010, respectively.

4 Includes reserve quantities related to production-sharing contracts (PSC) (refer to page E-11 for the definition of a PSC). PSC-related reserve quantities are 21 percent, 21 percent and 29 percent for consolidated companies for

2012, 2011 and 2010, respectively.

 Noteworthy amounts in the categories of natural gas proved-reserve changes for

2010 through 2012 are discussed below:

 Revisions In 2010, net revisions decreased reserves by 71 BCF. For

consolidated companies, a net increase in the United States of 220 BCF, primarily in

the mid-continent area and the Gulf of Mexico, was the result of a number of small

upward revisions related to improved reservoir performance and drilling activity,

none of which were individually significant. The increase was partially offset by

downward revisions due to the impact of higher prices on entitlement volumes in

Asia. For equity affiliates, a downward revision of 324 BCF at TCO was due to the

price effect on entitlement volumes and a change in the variable-royalty calculation.

This decline was partially offset

by the recognition of additional reserves related to the Angola LNG project.

 In 2011, net revisions increased reserves 497 BCF. For consolidated companies,

improved reservoir performance accounted for a majority of the 217 BCF increase in

the United States. In Asia, a net increase of 196 BCF was driven by development

drilling and improved field performance in Thailand, partially offset by the effects of

higher prices on entitlement volumes in Kazakhstan. For affiliated companies,

ongoing reservoir assessment resulted in the recognition of additional reserves related

to the Angola LNG project. At TCO, improved facility and reservoir performance

was more than offset by the price effect on entitlement volumes.

FS-72
 Table V Reserve Quantity Information - Continued

 In 2012, net revisions increased reserves 1,855 BCF. A net increase of 1,007

BCF in Asia was primarily due to development drilling and additional compression in

Bangladesh, and drilling results and improved field performance in Thailand. In

Australia, updated reservoir data interpretation based on additional drilling at the

Gorgon Project drove the 358 BCF increase. Drilling results from activities in the

Marcellus Shale were responsible for the majority of the 318 BCF increase in the

United States.

 Extensions and Discoveries In 2011, extensions and discoveries increased

reserves 4,680 BCF. In Australia, the Wheatstone Project accounted for the 4,035

BCF in additions. In Africa, the start of a new natural gas development project in

Nigeria resulted in the 290 BCF increase. In the United States, development drilling

accounted for the majority of the 287 BCF increase.

In 2012, extensions and discoveries increased reserves by 1,011 BCF. The increase

of 747 BCF in Australia was primarily related to positive drilling results at the

Gorgon Project.

 Purchases In 2011, purchases increased reserves 1,233 BCF. In the United

States, acquisitions in the Marcellus Shale increased reserves 1,230 BCF.

 Sales In 2011, sales decreased reserves 174 BCF. In Australia, the Wheatstone

Project unitization and equity sales agreements reduced reserves 77 BCF. In the

United States, sales in Alaska and other smaller fields reduced reserves 95 BCF.

 In 2012, sales decreased reserves by 538 BCF. Sales of a portion of the

company's equity interest in the Wheatstone Project were responsible for the 439

BCF reserves reduction in Australia.

FS-73
 Table VI Standardized Measure of Discounted Future Net Cash 

Flows Related to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows, related to the

preceding proved oil and gas reserves, is calculated in accordance with the

requirements of the FASB. Estimated future cash inflows from production are

computed by applying 12-month average prices for oil and gas to year-end quantities

of estimated net proved reserves. Future price changes are limited to those provided

by contractual arrangements in existence at the end of each reporting year. Future

development and production costs are those estimated future expenditures necessary

to develop and produce year-end estimated proved reserves based on year-end cost

indices, assuming continuation of year-end economic conditions, and include

estimated costs for asset retirement obligations. Estimated future income taxes are

calculated by applying appropriate year-end statutory tax rates. These rates reflect

allowable deductions and tax credits and are applied to estimated future pretax net

cash flows, less the tax basis of related assets. Discounted future net cash flows are

calculated

using 10 percent midperiod discount factors. Discounting requires a year-by-year

estimate of when future expenditures will be incurred and when reserves will be

produced.

 The information provided does not represent management’s estimate of the

company’s expected future cash flows or value of proved oil and gas reserves.

Estimates of proved-reserve quantities are imprecise and change over time as new

information becomes available. Moreover, probable and possible reserves, which may

become proved in the future, are excluded from the calculations. The valuation

prescribed by the FASB requires assumptions as to the timing and amount of future

development and production costs. The calculations are made as of December 31 each

year and should not be relied upon as an indication of the company’s future cash

flows or value of its oil and gas reserves. In the following table, “Standardized

Measure Net Cash Flows” refers to the standardized measure of discounted future

net cash flows.

Table VI - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

Consolidated Companies Affiliated Companies

Total 

Consolidated

Other and Affiliated

Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other Companies

At December 31, 2012

Future cash inflows

from production1 $ 139,856 $ 72,548 $122,189 $ 121,849 $ 134,009 $ 19,653 $ 610,104 $ 169,966 $ 47,496 $ 827,566

Future production

costs (46,173) (26,450) (24,591) (35,713) (18,340) (8,768) (160,035) (32,085) (19,899) (212,019)

Future development

costs (11,192) (11,925) (14,601) (17,275) (24,923) (1,946) (81,862) (12,355) (3,710) (97,927)

Future income taxes (31,647) (9,902) (48,683) (30,763) (27,224) (5,589) (153,808) (37,658) (13,363) (204,829)

Undiscounted future

net cash flows 50,844 24,271 34,314 38,098 63,522 3,350 214,399 87,868 10,524 312,791

10 percent midyear

annual discount for

timing of estimated

cash flows (21,416) (15,906) (12,430) (13,033) (40,450) (860) (104,095) (47,534) (5,644) (157,273)

Standardized Measure

Net Cash Flows $ 29,428 $ 8,365 $ 21,884 $ 25,065 $ 23,072 $ 2,490 $ 110,304 $ 40,334 $ 4,880 $ 155,518

At December 31, 2011

2

Future cash inflows

from production1 $ 143,633 $ 63,579 $ 124,077 $ 124,972 $ 113,773 $ 19,704 $ 589,738 $ 171,588 $ 42,212 $ 803,538

Future production

costs (39,523) (22,856) (22,703) (35,579) (15,411) (7,467) (143,539) (30,904) (19,430) (193,873)

Future development

costs (11,272) (9,345) (10,695) (15,035) (29,489) (676) (76,512) (10,778) (2,836) (90,126)

Future income taxes (34,050) (9,121) (53,103) (33,884) (20,661) (7,229) (158,048) (36,698) (10,833) (205,579)

Undiscounted future

net cash flows 58,788 22,257 37,576 40,474 48,212 4,332 211,639 93,208 9,113 313,960

10 percent midyear

annual discount for

timing of estimated

cash flows (25,013) (15,082) (13,801) (14,627) (35,051) (1,117) (104,691) (51,547) (4,883) (161,121)

Standardized Measure

Net Cash Flows $ 33,775 $ 7,175 $ 23,775 $ 25,847 $ 13,161 $ 3,215 $ 106,948 $ 41,661 $ 4,230 $ 152,839

At December 31, 2010

2

Future cash inflows

from production1 $ 101,281 $ 48,068 $ 90,402 $ 101,553 $ 52,635 $ 13,618 $ 407,557 $ 124,970 $ 31,188 $ 563,715

Future production

costs (36,609) (22,118) (19,591) (30,793) (9,191) (5,842) (124,144) (22,304) (4,172) (150,620)

Future development

costs (6,661) (6,953) (12,239) (11,690) (13,160) (708) (51,411) (8,777) (2,254) (62,442)

Future income taxes (20,307) (7,337) (34,405) (26,355) (9,085) (4,031) (101,520) (26,524) (12,919) (140,963)

Undiscounted future

net cash flows 37,704 11,660 24,167 32,715 21,199 3,037 130,482 67,365 11,843 209,690

10 percent midyear

annual discount for

timing of estimated

cash flows (13,218) (6,751) (9,221) (12,287) (15,282) (699) (57,458) (37,015) (6,574) (101,047)
Standardized Measure

Net Cash Flows $ 24,486 $ 4,909 $ 14,946 $ 20,428 $ 5,917 $ 2,338 $ 73,024 $ 30,350 $ 5,269 $ 108,643

1 Based on 12-month average price.

2 2011 and 2010 conformed to 2012 presentation.

FS-74
 Table VII Changes in the Standardized Measure of Discounted 

 Future Net Cash Flows From Proved Reserves

 The changes in present values between years, which can be significant, reflect

changes in estimated proved-reserve quantities and prices and assumptions used in

forecasting

production volumes and costs. Changes in the timing of production are included with

“Revisions of previous quantity estimates.”

Table VII - Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves

Total

Consolidated

and Affiliated

Millions of dollars Consolidated Companies Affiliated Companies Companies

Present Value at January 1, 2010 * $ 50,276 $ 27,236 $ 77,512

Sales and transfers of oil and gas produced net of production costs (39,047) (6,377) (45,424)

Development costs incurred 12,042 572 12,614

Purchases of reserves 513 — 513

Sales of reserves (47) — (47)

Extensions, discoveries and improved recovery less related costs 5,194 63 5,257

Revisions of previous quantity estimates 9,704 1,113 10,817

Net changes in prices, development and production costs 43,887 14,429 58,316

Accretion of discount 8,391 3,797 12,188

Net change in income tax (17,889) (5,214) (23,103)

Net change for 2010 22,748 8,383 31,131

Present Value at December 31, 2010 * $ 73,024 $ 35,619 $ 108,643

Sales and transfers of oil and gas produced net of production costs (52,338) (8,679) (61,017)

Development costs incurred 13,869 729 14,598

Purchases of reserves 1,212 — 1,212

Sales of reserves (803) — (803)

Extensions, discoveries and improved recovery less related costs 12,288 — 12,288

Revisions of previous quantity estimates 16,025 923 16,948

Net changes in prices, development and production costs 61,428 15,979 77,407

Accretion of discount 11,943 5,048 16,991

Net change in income tax (29,700) (3,728) (33,428)

Net change for 2011 33,924 10,272 44,196

Present Value at December 31, 2011 $ 106,948 $ 45,891 $ 152,839

Sales and transfers of oil and gas produced net of production costs (49,094) (7,708) (56,802)

Development costs incurred 18,013 942 18,955

Purchases of reserves 376 — 376

Sales of reserves (1,630) — (1,630)

Extensions, discoveries and improved recovery less related costs 11,303 106 11,409

Revisions of previous quantity estimates 23,556 3,759 27,315

Net changes in prices, development and production costs (19,179) (2,266) (21,445)

Accretion of discount 18,026 6,322 24,348

Net change in income tax 1,985 (1,832) 153

Net change for 2012 3,356 (677) 2,679

Present Value at December 31, 2012 $ 110,304 $ 45,214 $ 155,518

* 2011 and 2010 conformed to 2012 presentation.

FS-75
EXHIBIT INDEX

Exhibit No. Description

3.1 Restated Certificate of Incorporation of Chevron Corporation, dated May 30, 2008, filed as Exhibit 3.1 to Chevron Corporation’s Quarterly

Report on Form 10-Q for the quarterly period ended June 30, 2008, and incorporated herein by reference.

3.2 By-Laws of Chevron Corporation, as amended March 28, 2012, filed as Exhibit 3.1 to Chevron Corporation’s Current Report on Form 8-K

filed March 29, 2012, and incorporated herein by reference.

4.1 Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the company and its

consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent

of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Securities

and Exchange Commission upon request.

4.2 Confidential Stockholder Voting Policy of Chevron Corporation, filed as Exhibit 4.2 to Chevron Corporation’s Annual Report on Form 10-K

for the year ended December 31, 2008, and incorporated herein by reference.

10.1 Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.1 to Chevron Corporation’s

Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.

10.2 Chevron Incentive Plan, filed as Exhibit 10.2 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008,

and incorporated herein by reference.

10.3 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Annual Report on Form 10-K for the year

ended December 31, 2008, and incorporated herein by reference.

10.4 Chevron Corporation Deferred Compensation Plan for Management Employees, filed as Exhibit 10.5 to Chevron Corporation’s Current

Report on Form 8-K filed December 13, 2005, and incorporated herein by reference.

10.5 Chevron Corporation Deferred Compensation Plan for Management Employees II, filed as Exhibit 10.5 to Chevron Corporation’s Annual

Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.

10.6 Chevron Corporation Retirement Restoration Plan, filed as Exhibit 10.6 to Chevron Corporation’s Annual Report on Form 10-K for the year

ended December 31, 2008, and incorporated herein by reference.

10.7 Chevron Corporation ESIP Restoration Plan, filed as Exhibit 10.7 to Chevron Corporation’s Annual Report on Form 10-K for the year ended

December 31, 2008, and incorporated herein by reference.

10.8 Texaco Inc. Director and Employee Deferral Plan, filed as Exhibit 10.16 to Chevron Corporation’s Annual Report on Form 10-K for the year

ended December 31, 2001, and incorporated herein by reference.

10.9* Summary of Chevron Incentive Plan Award Criteria.

10.1 Chevron Corporation Change in Control Surplus Employee Severance Program for Salary Grades 41 through 43, filed as Exhibit 10.1 to

Chevron Corporation’s Current Report on Form 8-K filed December 12, 2006, and incorporated herein by reference.

10.11 Chevron Corporation Benefit Protection Program, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed

December 12, 2006, and incorporated herein by reference.

10.12 Form of Terms and Conditions for Awards under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron

Corporation’s Current Report on Form 8-K filed February 1, 2011, and incorporated herein by reference.

 10.13* Form of Restricted Stock Unit Grant Agreement under the Long-Term Incentive Plan of Chevron Corporation.

10.14 Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan,

filed as Exhibit 10.17 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein

by reference.

10.15 Form of Stock Units Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as

Exhibit 10.19 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by

reference.

 10.16 Agreement between Chevron Corporation and R. Hewitt Pate, filed as Exhibit 10.16 to Chevron's Annual Report on Form 10-K for the year

ended December 31, 2011, and incorporated herein by reference.

12.1* Computation of Ratio of Earnings to Fixed Charges (page E-3).

21.1* Subsidiaries of Chevron Corporation (pages E-4 through E-5).

E-1
Exhibit No. Description

23.1* Consent of PricewaterhouseCoopers LLP (page E-6).

24.1 to 24.9*

Powers of Attorney for directors and certain officers of Chevron Corporation, authorizing the signing of the Annual Report on Form 10-K

on their behalf.

31.1* Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Executive Officer (page E-7).

31.2* Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Financial Officer (page E-8).

32.1* Section 1350 Certification of the company’s Chief Executive Officer (page E-9).

32.2* Section 1350 Certification of the company’s Chief Financial Officer (page E-10).

95* Mine Safety Disclosure.

99.1* Definitions of Selected Energy and Financial Terms (pages E-11 through E-12).

101.INS* XBRL Instance Document.

101.SCH* XBRL Schema Document.

101.CAL* XBRL Calculation Linkbase Document.

101.LAB* XBRL Label Linkbase Document.

101.PRE* XBRL Presentation Linkbase Document.

101.DEF* XBRL Definition 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.”

_______________________________

* Filed herewith.

Copies of above the 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.

E-2
Exhibit 10.9

SUMMARY OF CHEVRON INCENTIVE PLAN AWARD CRITERIA

The Chevron Incentive Plan (CIP) (formerly the Management Incentive Plan of Chevron Corporation) is an annual cash incentive plan that links awards to

performance results of the prior year. Chevron’s named executive officers (NEOs) are eligible to receive awards under the CIP. CIP awards are designed to

reward plan participants, including the NEOs, for business and individual performance.

Prior to each performance year (i.e. fiscal year), the Board’s Management Compensation Committee establishes a CIP Award Target (explained under “CIP

Award Target” below) for each NEO, which is based on a percentage of the NEO’s base salary. After the end of the performance year, the Committee assesses

Chevron’s overall performance and sets a Corporate Performance Rating (explained under “Chevron’s Corporate Performance” below), which is the same for

each NEO. The Committee then determines the cash amount for each NEO’s CIP award by multiplying the NEO’s CIP Award Target by the Corporate

Performance Rating, and then adjusting the number to take into account the NEO’s individual performance, including the performance of any strategic

business units reporting to the NEO. The Corporate Performance Rating and the NEO’s individual performance are not determined by a formula or on the

basis of predetermined financial targets or award ranges. Rather, the Committee exercises its discretion based upon a number of factors discussed below. With

respect to each NEO other than the CEO, the CEO makes a recommendation to the Committee.

CIP Award Target. The CIP Award Target is a percentage of the NEO’s base salary and is set prior to the beginning of the performance year as an appropriate

starting point for determining the actual size of the NEO’s CIP award. The Committee sets the percentage of base salary for each salary grade to be competitive

with similar awards to persons in similar positions at companies in Chevron’s Oil Industry Peer Group (viz. Anadarko Petroleum, Hess, BP, ConocoPhillips,

Devon Energy, Exxon Mobil, Marathon Oil, Occidental Petroleum, Royal Dutch Shell, Sunoco, Tesoro and Valero Energy).

Chevron’s Corporate Performance. After the end of the performance year, the Committee sets the Corporate Performance Rating based on its assessment of how

Chevron performed. The Committee considers numerous metrics in setting the Corporate Performance Rating, including earnings, relative indexed earnings per

share, return on capital employed, and Chevron’s total stockholder return ranking and Chevron’s return on capital employed ranking. The Committee does

not have a set formula for evaluation of these metrics, but rather exercises its discretion, taking into account how Chevron performed in light of its business

plan objectives. Also, given the long-term nature of the business, in which investments today yield returns for decades to come, the Committee also considers

decisions and progress on strategic investments. The Committee also focuses on nonfinancial items, such as safety, operational excellence, cost management,

oil and gas production, reliability of facilities and operations, and progress on strategic projects and investments for the future of the business. The Committee

considers Chevron’s performance in these areas on both an absolute and relative basis, comparing our performance against the performance of our top

competitors in the Oil Industry Peer Group (viz. BP, ConocoPhillips, Exxon Mobil and Royal Dutch Shell) and considering these in light of matters beyond

management’s control, such as commodity price effects, industry mergers and acquisitions, and foreign exchange. The Corporate Performance Rating is the

same for each plan participant, including each NEO.

Individual Performance. After the Committee has applied the Corporate Performance Rating to the CIP Award Target for each NEO, the Committee exercises its

discretion in further adjusting the final CIP award to take into account individual performance, which includes consideration of business performance in the

areas of responsibility reporting to the NEO. The Committee also considers internal pay equity to ensure that NEOs in the same base salary grade are

positioned properly. The Committee does not use a predetermined set of metrics, targets or formula in considering individual performance. Instead, the

Committee uses its judgment in analyzing the individual performance of each NEO, including how any business units reporting to the NEO performed.

Chevron reports annual CIP awards to each of its NEOs in its Annual Report on Form 10-K or its annual Proxy Statement.
Exhibit 10.13

Form of Restricted Stock Unit Grant Agreement under the Long-Term Incentive Plan of Chevron Corporation.

Restricted Stock Unit Grant Agreement dated < DATE>, between CHEVRON CORPORATION (“Corporation”), and < NAME>.

The Management Compensation Committee (the “Committee”) has selected you to receive a special Restricted Stock Unit award under the Chevron Corporation Long-Term

Incentive Plan. Capitalized terms not defined in this Agreement shall have the same meaning as the defined terms in the Chevron Corporation Long-Term

Incentive Plan, as amended from time to time (the “Plan”). This award is governed by the Plan and is subject to the following special terms:

1. You have been awarded <X,XXX> Restricted Stock Units on <DATE>.

2. The restrictions on the Restricted Stock Units shall lapse and you shall be vested as follows: <VEST TERMS>, provided that your employment with the

Corporation is not Terminated prior to the respective vesting dates.

3. Vested Restricted Stock Units will be paid in cash, valued based on the closing price of a share of stock of the Corporation on the vesting date.

4. Vested amounts are taxable as ordinary income and cash payment will be net of any required tax withholding.

5. Your Restricted Stock Units shall be paid within 30 days after the respective vesting date. In no event will payment be made more than two and one-half months

following the end of the calendar year in which the Restricted Stock Unit award vests.

6. No deferral of the payment date shall be permitted under this Agreement.

7. The Restricted Stock Units representing this award shall be subject to adjustment for Recapitalization in the manner provided in the Plan, as it may be amended from

time-to-time.

8. Your Restricted Stock Units will earn Dividend Equivalents when Chevron pays a dividend on its common shares, in the form of additional Restricted Stock Units.

9. No certificate for shares of stock shall be issued at the time the grant is made and you shall have no right to or interest in shares of stock of the Corporation as the

result of this grant agreement.

10. Prior to distribution of your Restricted Stock Units, if you are terminated by the Corporation for “Misconduct” as defined in the Plan, the award shall be canceled

unless the Committee, in its sole discretion, elects not to cancel such award. In addition, with respect to any restricted stock units that became vested and paid after the date

of your Misconduct: (i) any such payment may be forfeited and (ii) the Corporation may demand that you pay over to the Corporation any such payment you received.

11. This award under this Agreement may not be transferred by you during your lifetime and may not be assigned, pledged or otherwise transferred except by the laws

of descent and distribution.

12. This Agreement shall not confer on you the right to continued employment by the Corporation, nor shall this award interfere in any way with the right of the

Corporation to terminate your employment at any time.

13. This Agreement is not subject to any provisions of the Employee Retirement Income Security Act (ERISA) of 1974.

14. This award is subject to your signing the enclosed copy of this agreement and returning it in the envelope provided. By accepting this award, you agree to keep this

agreement and all of its provisions confidential and not to disclose any parts thereof to third parties, except that information relating to this agreement may be divulged (i) to

the extent required by any court order, (ii) to any public authority such as the IRS, (iii) in connection with any tax filing or (iv) to any financial advisors or tax consultants.

Please retain the original of this Agreement with your important papers.

Accepted:

__________________________
Exhibit 12.1

CHEVRON CORPORATION — TOTAL ENTERPRISE BASIS

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

Year Ended December 31

2012 2011 2010 2009 2008

(Millions of dollars)

Net Income Attributable to Chevron Corporation $ 26,179 $ 26,895 $ 19,024 $ 10,483 $ 23,931

Income Tax Expense 19,996 20,626 12,919 7,965 19,026

Distributions Less Than Equity in Earnings of Affiliates

(1,351) (570) (501) (103) (440)

Noncontrolling Interests 157 113 112 80 100

Previously Capitalized Interest Charged to Earnings During Period 123 117 240 261 91

Interest and Debt Expense — — 50 28 —

Interest Portion of Rentals (1)

316 288 300 299 274

Earnings Before Provision for Taxes and Fixed Charges $ 45,420 $ 47,469 $ 32,144 $ 19,013 $ 42,982

Interest and Debt Expense — — 50 28 —

Interest Portion of Rentals (1)

316 288 300 299 274

Preferred Stock Dividends of Subsidiaries — — — — —

Capitalized Interest 230 288 267 273 256

Total Fixed Charges $ 546 $ 576 $ 617 $ 600 $ 530

Ratio of Earnings to Fixed Charges 83.19 82.41 52.10 31.69 81.10

(1) Calculated as one-third of rentals. Considered a reasonable approximation of interest factor.

E-3
Exhibit 21.1

SUBSIDIARIES OF CHEVRON CORPORATION1

At December 31, 2012

Name of Subsidiary State, Province or Country in Which Organized

Beta Offshore Nigeria Deepwater Limited Nigeria

Cabinda Gulf Oil Company Limited Bermuda

Chevron Argentina S.R.L. Argentina

Chevron Australia Pty Ltd. Australia

Chevron Australia Transport Pty Ltd. Australia

Chevron (Bermuda) Investments Limited Bermuda

Chevron Brasil Petróleo Limitada Brazil

Chevron Canada Limited Canada

Chevron Caspian Pipeline Consortium Company Delaware

Chevron Environmental Management Company California

Chevron Geothermal Indonesia, Ltd. Bermuda

Chevron Global Energy Inc. Delaware

Chevron Global Technology Services Company Delaware

Chevron International (Congo) Limited Bermuda

Chevron International Petroleum Company Delaware

Chevron Investment Management Company Delaware

Chevron LNG Shipping Company Limited Bermuda

Chevron Marine Products LLC Delaware

Chevron Nigeria Deepwater B Limited Nigeria

Chevron Nigeria Deepwater D Limited Nigeria

Chevron Nigeria Limited Nigeria

Chevron Oil Congo (D.R.C.) Limited Bermuda

Chevron Oronite Company LLC Delaware

Chevron Oronite Pte. Ltd. Singapore

Chevron Oronite S.A.S. France

Chevron Overseas Company Delaware

Chevron Overseas (Congo) Limited Bermuda

Chevron Overseas Petroleum Limited Bahamas

Chevron Overseas Pipeline (Cameroon) Limited Bahamas

Chevron Overseas Pipeline (Chad) Limited Bahamas

Chevron Pakistan Limited Bahamas

Chevron Petroleum Chad Company Limited Bermuda

Chevron Petroleum Company New Jersey

Chevron Petroleum Limited Bermuda

Chevron Philippines Inc. Philippines

Chevron Pipe Line Company Delaware

Chevron South Natuna B Inc. Liberia

Chevron Thailand Exploration and Production, Ltd. Bermuda

Chevron (Thailand) Limited Bahamas

Chevron Thailand LLC Delaware

Chevron Transport Corporation Ltd. Bermuda

E-4
Name of Subsidiary State, Province or Country in Which Organized

Chevron United Kingdom Limited England and Wales

Chevron U.S.A. Holdings Inc. Delaware

Chevron U.S.A. Inc. Pennsylvania

Oilfield Concession Operators Limited Nigeria

PT Chevron Pacific Indonesia Indonesia

Saudi Arabian Chevron Inc. Delaware

Texaco Britain Limited England and Wales

Texaco Capital Inc. Delaware

Texaco Captain Inc. Delaware

Texaco Inc. Delaware

Texaco Overseas Holdings Inc. Delaware

Texaco Venezuela Holdings (I) Company Delaware

TRMI-H LLC Delaware

Union Oil Company of California California

Unocal Corporation Delaware

Unocal International Corporation Nevada

Unocal Pipeline Company California

West Australian Petroleum Pty Limited Australia

1 All of the subsidiaries in the above list are wholly owned, either directly or indirectly, by Chevron Corporation. Certain subsidiaries are not listed since, considered in the

aggregate as a single subsidiary, they would not constitute a significant subsidiary at December 31, 2012.

E-5
Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 of Chevron Corporation and its subsidiaries (No. 333-184777),

and to the incorporation by reference in the Registration Statements on Form S-8 of Chevron Corporation and its subsidiaries (Nos. 333-172428, 333-171066,

333-26731, 333-162660, 333-152846, 333-102269, 333-72672, 333-21805, 333-21807, 333-21809, 333-46261, 333-105136, 333-122121, 333-02011, 333-

127558, 333-127559, 333-127560, 333-127561, 333-127563, 333-127564, 333-127565, 333-127566, 333-127568, 333-128733, 333-128734, 333-

127567, 333-127569, 333-127570), of our report dated February 22, 2013, relating to the consolidated financial statements, financial statement schedule

and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP 

San Francisco, California

February 22, 2013

E-6
Exhibit 24.1

POWER OF ATTORNEY

WHEREAS, Chevron Corporation, a Delaware corporation (the "Corporation"), contemplates filing with the Securities and Exchange Commission

in Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual

Report on Form 10-K for the year ended December 31, 2012;

WHEREAS, the undersigned is an officer or director, or both, of the Corporation;

NOW, THEREFORE, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, CHRISTOPHER A. BUTNER, and KARI H.

ENDRIES, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name,

place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same,

with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and

agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all

intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes,

may lawfully do and cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 4th day of January, 2013.

/s/ Linnet F. Deily 
Exhibit 24.2

POWER OF ATTORNEY

WHEREAS, Chevron Corporation, a Delaware corporation (the "Corporation"), contemplates filing with the Securities and Exchange Commission

in Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual

Report on Form 10-K for the year ended December 31, 2012;

WHEREAS, the undersigned is an officer or director, or both, of the Corporation;

NOW, THEREFORE, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, CHRISTOPHER A. BUTNER, and KARI H.

ENDRIES, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name,

place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same,

with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and

agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all

intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes,

may lawfully do and cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 29 th day of December, 2012.

/s/ Robert E. Denham 
Exhibit 24.3

POWER OF ATTORNEY

WHEREAS, Chevron Corporation, a Delaware corporation (the "Corporation"), contemplates filing with the Securities and Exchange Commission

in Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual

Report on Form 10-K for the year ended December 31, 2012;

WHEREAS, the undersigned is an officer or director, or both, of the Corporation;

NOW, THEREFORE, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, CHRISTOPHER A. BUTNER, and KARI H.

ENDRIES, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name,

place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same,

with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and

agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all

intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes,

may lawfully do and cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 23rd day of December, 2012.

/s/ Alice P. Gast 
Exhibit 24.4

POWER OF ATTORNEY

WHEREAS, Chevron Corporation, a Delaware corporation (the "Corporation"), contemplates filing with the Securities and Exchange Commission

in Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual

Report on Form 10-K for the year ended December 31, 2012;

WHEREAS, the undersigned is an officer or director, or both, of the Corporation;

NOW, THEREFORE, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, CHRISTOPHER A. BUTNER, and KARI H.

ENDRIES, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name,

place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same,

with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and

agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all

intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes,

may lawfully do and cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 27 th day of December, 2012.

/s/ Enrique Hernandez, Jr. 

 
Exhibit 24.5

POWER OF ATTORNEY

WHEREAS, Chevron Corporation, a Delaware corporation (the "Corporation"), contemplates filing with the Securities and Exchange Commission

in Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual

Report on Form 10-K for the year ended December 31, 2012;

WHEREAS, the undersigned is an officer or director, or both, of the Corporation;

NOW, THEREFORE, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, CHRISTOPHER A. BUTNER, and KARI H.

ENDRIES, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name,

place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same,

with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and

agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all

intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes,

may lawfully do and cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 1 st day of January, 2013.

/s/ Charles W. Moorman 

 
Exhibit 24.6

POWER OF ATTORNEY

WHEREAS, Chevron Corporation, a Delaware corporation (the "Corporation"), contemplates filing with the Securities and Exchange Commission

in Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual

Report on Form 10-K for the year ended December 31, 2012;

WHEREAS, the undersigned is an officer or director, or both, of the Corporation;

NOW, THEREFORE, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, CHRISTOPHER A. BUTNER, and KARI H.

ENDRIES, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name,

place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same,

with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and

agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all

intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes,

may lawfully do and cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 30 th day of January, 2013.

/s/ Kevin W. Sharer 

 
Exhibit 24.7

POWER OF ATTORNEY

WHEREAS, Chevron Corporation, a Delaware corporation (the "Corporation"), contemplates filing with the Securities and Exchange Commission

in Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual

Report on Form 10-K for the year ended December 31, 2012;

WHEREAS, the undersigned is an officer or director, or both, of the Corporation;

NOW, THEREFORE, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, CHRISTOPHER A. BUTNER, and KARI H.

ENDRIES, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name,

place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same,

with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and

agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all

intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes,

may lawfully do and cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 30 th day of January, 2013.

/s/ John G. Stumpf 

 
Exhibit 24.8

POWER OF ATTORNEY

WHEREAS, Chevron Corporation, a Delaware corporation (the "Corporation"), contemplates filing with the Securities and Exchange Commission

in Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual

Report on Form 10-K for the year ended December 31, 2012;

WHEREAS, the undersigned is an officer or director, or both, of the Corporation;

NOW, THEREFORE, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, CHRISTOPHER A. BUTNER, and KARI H.

ENDRIES, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name,

place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same,

with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and

agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all

intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes,

may lawfully do and cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 20 th day of December, 2012.

/s/ Ronald D. Sugar 

 
Exhibit 24.9

POWER OF ATTORNEY

WHEREAS, Chevron Corporation, a Delaware corporation (the "Corporation"), contemplates filing with the Securities and Exchange Commission

in Washington, D.C., under the provisions of the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder, an Annual

Report on Form 10-K for the year ended December 31, 2012;

WHEREAS, the undersigned is an officer or director, or both, of the Corporation;

NOW, THEREFORE, the undersigned hereby constitutes and appoints LYDIA I. BEEBE, CHRISTOPHER A. BUTNER, and KARI H.

ENDRIES, or any of them, his or her attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in his or her name,

place and stead, in any and all capacities, to sign the aforementioned Annual Report on Form 10-K (and any and all amendments thereto) and to file the same,

with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and

agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all

intents and purposes he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes,

may lawfully do and cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereunto set his or her hand this 30 th day of January, 2013.

/s/ Carl Ware 

 
Exhibit 31.1

RULE 13a-14(a)/15d-14(a) CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John S. Watson, certify that:

1. I have reviewed this Annual Report on Form 10-K of Chevron Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the

statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this

report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the

financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,

to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within

those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our

supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for

external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the

effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent

fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to

materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the

registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably

likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control

over financial reporting.

/S/ JOHN S. WATSON

John S. Watson

Chairman of the Board and

Chief Executive Officer

Dated: February 22, 2013

E-7
Exhibit 31.2

RULE 13a-14(a)/15d-14(a) CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Patricia E. Yarrington, certify that:

1. I have reviewed this Annual Report on Form 10-K of Chevron Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the

statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this

report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the

financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to

ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those

entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our

supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for

external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the

effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent

fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to

materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the

registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably

likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control

over financial reporting.

/S/ PATRICIA E. YARRINGTON

Patricia E. Yarrington

Vice President and

Chief Financial Officer

Dated: February 22, 2013

E-8
Exhibit 32.1

CERTIFICATION PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002 (18 U.S.C. SECTION 1350)

In connection with the Annual Report of Chevron Corporation (the “Company”) on Form 10- K for the period ended December 31, 2012, as filed with the

Securities and Exchange Commission on the date hereof (the “Report”), I, John S. Watson, Chairman and Chief Executive Officer of the Company, certify,

pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/S/ JOHN S. WATSON

John S. Watson

Chairman of the Board and

Chief Executive Officer

Dated: February 22, 2013

E-9
Exhibit 32.2

CERTIFICATION PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002 (18 U.S.C. SECTION 1350)

In connection with the Annual Report of Chevron Corporation (the “Company”) on Form 10- K for the period ended December 31, 2012, as filed with the

Securities and Exchange Commission on the date hereof (the “Report”), I, Patricia E. Yarrington, Vice President and Chief Financial Officer of the Company,

certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge: 

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/S/ PATRICIA E. YARRINGTON

Patricia E. Yarrington

Vice President and

Chief Financial Officer

Dated: February 22, 2013

E-10
Exhibit 95

Mine Safety Disclosure

Chevron is or has been an operator of the following coal and molybdenum mines for which reporting requirements apply under Section 1503 of the DoddFrank Wall Street Reform and Consumer Protection Act, as a result of citations and orders received from the Mine Safety and Health Administration (MSHA)

during the year ending December 31, 2012. In evaluating this information, consideration should be given to factors such as: (i) the number of citations and

orders will vary depending on the size of the mine, (ii) the number of citations issued will vary from inspector to inspector and mine to mine, and (iii) citations

and orders can be contested and appealed, and in that process, are often reduced in severity and amount, and are sometimes dismissed.

The items in the table below refer to the applicable sections of the Federal Mine Safety and Health Administration Act of 1977 under which reporting is

required for the year ending December 31, 2012.

Mine

Section

104

S&S

Citations

(#)

Section

104(b)

Orders

(#)

Section

104(d)

Citations

And

Orders

(#)

Section

110(b)(2)

Violations

(#)

Section

107(a)

Orders

(#)

Total Dollar

Value of

MSHA

Assess-ments

Proposed

($1,000)

Total 

Number 

of

Mining 

Related 

Fatalities

(#)

Received 

Notice of 

Pattern 

of 

Violation 

Under 

Section 

104(e)

(yes/no)

Received 

Notice of 

Potential 

to Have 

Pattern 

of 

Violation 

Under 

Section 

104(e)

(yes/no)

Legal

Actions

Pending 

as of 

Last 

Day of 

Period

(#)

Legal 

Actions 

Initiated 

During 

Period

(#)

Legal 

Actions 

Resolved 

During 

Period

(#)

Kemmerer Mine (1) — — — — — — — no no — — 8

 McKinley Mine

1 — — — — $14 — no no 1 1 1

North River 

Mine(2) — — — — — — — no no 2 — 22

 Questa Mine

9 — — — — $9 — no no — — —

(1) The Kemmerer Mine was sold January 31, 2012.

(2) The North River Mine was sold May 6, 2011.
Exhibit 99.1

DEFINITIONS OF SELECTED ENERGY TERMS

Barrels of oil-equivalent (BOE)

A unit of measure to quantify crude oil, natural gas liquids and natural gas amounts using the same basis. Natural gas volumes are converted to barrels on the

basis of energy content. See oil-equivalent gas and production.

Development

Drilling, construction and related activities following discovery that are necessary to begin production and transportation of crude oil and natural gas.

Exploration

Searching for crude oil and/or natural gas by utilizing geologic and topographical studies, geophysical and seismic surveys, and drilling of wells.

Gas-to-liquids (GTL)

A process that converts natural gas into high-quality transportation fuels and other products.

Liquefied natural gas (LNG)

Natural gas that is liquefied under extremely cold temperatures to facilitate storage or transportation in specially designed vessels.

Liquefied petroleum gas (LPG)

Light gases, such as butane and propane, that can be maintained as liquids while under pressure.

Oil-equivalent gas (OEG)

The volume of natural gas needed to generate the equivalent amount of heat as a barrel of crude oil. Approximately 6,000 cubic feet of natural gas is equivalent

to one barrel of crude oil.

Oil sands

Naturally occurring mixture of bitumen – a heavy, viscous form of crude oil – water, sand and clay. Using hydroprocessing technology, bitumen can be

refined to yield synthetic oil.

Price Effects on Entitlement Volumes

The impact on Chevron’s share of net production and net proved reserves due to changes in crude oil and natural gas prices between periods. Under

production-sharing and variable-royalty provisions of certain agreements, price variability can increase or decrease royalty burdens and/or volumes

attributable to the company. For example, at higher prices, fewer volumes are required for Chevron to recover its costs under certain production-sharing

contracts.

Production

Total production refers to all the crude oil (including synthetic oil), natural gas liquids and natural gas produced from a property. Net production is gross

production minus both royalties paid to landowners and a government’s agreed-upon share of production under a production-sharing contract. Liquids

production refers to crude oil, condensate, natural gas liquids and synthetic oil volumes. Oil-equivalent production is the sum of the barrels of liquids and

the oil-equivalent barrels of natural gas produced. See barrels of oil-equivalent and oil-equivalent gas.

Production-sharing contract (PSC)

An agreement between a government and a contractor (generally an oil and gas company) whereby production is shared between the parties in a prearranged

manner. The contractor typically incurs all exploration, development and production costs, which are subsequently recoverable out of an agreed-upon share of

any future PSC production, referred to as cost recovery oil and/or gas. Any remaining production, referred to as profit oil and/or gas, is shared between the

parties on an agreed-upon basis as stipulated in the PSC. The government may also retain a share of PSC production as a royalty payment, and the contractor

typically owes income tax on its portion of the profit oil or gas. The contractor’s share of PSC oil and/or gas production and reserves varies over time, as it is

dependent on prices, costs and specific PSC terms.

Reserves

Crude oil or natural gas contained in underground rock formations called reservoirs and saleable hydrocarbons extracted from oil sands, shale, coalbeds or

other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas. Net proved reserves are the estimated quantities that geoscience

and engineering data demonstrate with reasonable certainty to be

E-11
economically producible in the future from known reservoirs under existing economic conditions, operating methods and government regulations, and exclude

royalties and interests owned by others. Estimates change as additional information becomes available. Oil-equivalent reserves are the sum of the liquids

reserves and the oil-equivalent gas reserves. See barrels of oil-equivalent and oil-equivalent gas. The company discloses only net proved reserves in its

filings with the U.S. Securities and Exchange Commission.

Shale gas

Natural gas produced from shale (very fine grained rock) formations where the gas was sourced from within the shale itself and is trapped in rocks with low

porosity and extremely low permeability. Production of shale gas requires the use of hydraulic fracturing (pumping a fluid-sand mixture into the formation

under high pressure) to help produce the gas.

Synthetic oil

A marketable and transportable hydrocarbon liquid, resembling crude oil, that is produced by upgrading highly viscous or solid hydrocarbons, such as

extra-heavy crude oil or oil sands.

DEFINITIONS OF SELECTED FINANCIAL TERMS

Earnings

The term earnings is net income attributable to Chevron Corporation as presented on the Consolidated Statement of Income.

Return on capital employed (ROCE)

ROCE is calculated by dividing earnings (adjusted for after-tax interest expense and noncontrolling interests) by the average of total debt, noncontrolling

interests and Chevron Corporation stockholders’ equity for the year.

Return on stockholders’ equity

Return on stockholders’ equity is earnings divided by average Chevron Corporation stockholders’ equity. Average Chevron Corporation stockholders’ equity

is computed by averaging the sum of the beginning-of-year and end-of-year balances.

E-12