CVX-12.31.12-10K DOC



 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
 
þ  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 
þ          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 þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes 
þ          No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes þ          No 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 þ
 
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 þ
 
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.
 
3
 
 
3
 
 
4
 
 
4
 
 
           Upstream
4
 
 
           Downstream 
24
 
 
           Other Businesses 
26
 
 
28
 
28
 
30
 
30
 
30
 
30
 
31
 
31
 
31
 
31
 
31
 
32
 
32
 
32
 
33
 
34
 
34
 
34
 
34
 
35
 
 
36
 
 
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-than-expected 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.
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

 
65

 
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 oil-equivalent 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.




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     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 oil-equivalent 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 oil-equivalent 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 five-year 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 oil-equivalent. 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 oil-equivalent 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 Atyrau-Samara (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 oil-equivalent 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 shallow-water 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. Start-up 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-per-year 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 two-train, 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 company-operated 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 partner-operated Danish Underground Consortium (DUC), which produces crude oil and natural gas from 13 fields in the Danish North Sea. Net oil-equivalent 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 million-acre 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

 
99

 
   Other Petroleum Products1
94

 
99

 
95

 
   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 Products1 
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 dynamic-positioning 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 enhanced-oil-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), weather-related 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, capital-intensive 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 short-term 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 13a-15(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
56
 
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
55
 
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
56
 
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) 
 
 
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




























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38




 
Financial Table of Contents
 
 
 
 
 
 
 
 
 
 
 
FS-2
 
FS-28
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Taxes FS-43
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
FS-21
 
 
 
 
 
Equity FS-55
 
 
 
 
 
Consolidated Financial Statements
 
 
 
 
 
 
 
 
 
 
Note 26
 
Acquisition of Atlas Energy, Inc. FS-60
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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-and-demand conditions for such materials and services. Capital and exploratory expenditures and operating expenses can also be affected by damage to production facilities caused by severe weather or civil unrest.
     The 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, low-sulfur) crudes and those of lower quality (low-gravity, high-sulfur). The amount of the differential in any period is associated with the supply of heavy crude available versus the demand, which is a function of the 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-and-demand 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 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.
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. Oil-equivalent 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 Obligations1
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-or-Pay 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 20142015 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 Inter-Continental 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 long-term 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-and-demand 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 revenues1
$
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 gas-to-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 before-tax 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 associ-



 
ated 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 long-lived 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 Kazakh-


FS-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 Equipment1
 
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
33


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 represen-





FS-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 high-tax-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 expira-




 
tion 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
$
65

 
 
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 stock-based 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 4070 percent, Fixed Income and Cash 2065 percent, Real Estate 015 percent, and Other 05 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 5070 percent and Fixed Income and Cash 3050 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 earnings-per-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 FS-43, 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 Rehabilita-










FS-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 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$3,700; 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 mate-









 
rial 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 Development1
 
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 FS-38, 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 Activities
1
 


     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, 38 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