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Chevron Corporation 10-K 2010
e10vk
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
þ  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2009
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 1-368-2
(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 Number)
  (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. (Check one):
 
             
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 — $132,865,210,015 (As of June 30, 2009)
 
Number of Shares of Common Stock outstanding as of February 19, 2010 — 2,008,352,638
 
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
 
Notice of the 2010 Annual Meeting and 2010 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2010 Annual Meeting of Stockholders (in Part III)
 
 


 

 
 
                 
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PART II
 
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 EX-99.1
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT


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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,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “budgets” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond the company’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
 
Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude-oil and natural-gas prices; changing refining, marketing and chemical margins; actions of competitors or regulators; timing of exploration expenses; timing of crude-oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude-oil and natural-gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company’s net production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or crude-oil production quotas that might be imposed by the Organization of Petroleum Exporting Countries; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; the potential liability resulting from other pending or future litigation; the company’s future acquisition or disposition of assets and gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign-currency movements compared with the U.S. dollar; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” on pages 30 through 32 in this report. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.


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Item 1.   Business
 
(a)   General Development of Business
 
 
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 operations, power generation and energy services. Exploration and production (upstream) operations consist of exploring for, developing and producing crude oil and natural gas and also marketing natural gas. Refining, marketing and transportation (downstream) operations relate to refining crude oil and converting natural gas into finished petroleum products; marketing crude oil and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipeline, marine vessel, motor equipment and rail car. Chemicals operations include the manufacture and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant oil additives.
 
A list of the company’s major subsidiaries is presented on pages E-23 and E-24. As of December 31, 2009, Chevron had approximately 64,000 employees (including about 4,000 service station employees). Approximately 31,500 employees (including about 3,500 service station employees), or 49 percent, were employed in U.S. operations.
 
 
Petroleum industry operations and profitability are influenced by many factors, and individual petroleum companies have little control over some of them. Governmental policies, particularly in the areas of taxation, energy and the environment, have a significant impact on petroleum activities, regulating how companies are structured and where and how companies conduct their operations and formulate their products and, in some cases, limiting their profits directly. Prices for crude oil, natural gas, petroleum products and petrochemicals are generally determined by supply and demand for these commodities. However, some governments impose price controls on refined products such as gasoline or diesel fuel. 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. Seasonality is not a primary driver of changes in the company’s quarterly earnings during the year.
 
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 also competes with fully integrated major petroleum companies and other independent refining, marketing and transportation entities and national petroleum companies in the sale or acquisition of various goods or services in many national and international markets.
 
 
Refer to pages FS-2 through FS-9 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.
 
 
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, it does 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.


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Chevron’s primary objective is to create stockholder 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 gas business. In the downstream, the strategies are to improve returns and selectively grow, with a focus on integrated value creation. The company also continues to invest in renewable-energy technologies, with an objective of capturing profitable positions.
 
(b)   Description of Business and Properties
 
The upstream, downstream and chemicals activities of the company and its equity affiliates are widely dispersed geographically, with operations in North America, South America, Europe, Africa, the Middle East, Asia and Australia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2009, and assets as of the end of 2009 and 2008 — for the United States and the company’s international geographic areas — are in Note 11 to the Consolidated Financial Statements beginning on page FS-40. Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Notes 12 and 13 on pages FS-43 through FS-45.
 
 
Total expenditures for 2009 were $22.2 billion, including $1.6 billion for the company’s share of equity-affiliate expenditures. In 2008 and 2007, expenditures were $22.8 billion and $20 billion, respectively, including the company’s share of affiliates’ expenditures of $2.3 billion in both periods.
 
Of the $22.2 billion in expenditures for 2009, about three-fourths, or $17.1 billion, was related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2008 and 2007. International upstream accounted for about 80 percent of the worldwide upstream investment in 2009 and about 70 percent in 2008 and 2007, reflecting the company’s continuing focus on opportunities available outside the United States.
 
In 2010, the company estimates capital and exploratory expenditures will be $21.6 billion, including $1.6 billion of spending by affiliates. About 80 percent of the total, or $17.3 billion, is budgeted for exploration and production activities, with $13.2 billion of that amount for projects outside the United States.
 
Refer also to a discussion of the company’s capital and exploratory expenditures on page FS-12.
 
 
The table on the following page summarizes the net production of liquids and natural gas for 2009 and 2008 by the company and its affiliates.


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Components of Oil-Equivalent
            Crude Oil & Natural Gas
       
    Oil-Equivalent (Thousands
  Liquids (Thousands of
  Natural Gas (Millions of
    of Barrels per Day)   Barrels per Day)   Cubic Feet per Day)
    2009   2008   2009   2008   2009   2008
United States
    717       671       484       421       1,399       1,501  
Africa:
                                               
Nigeria
    232       154       225       142       48       72  
Angola
    150       154       141       145       49       52  
Chad
    27       29       26       28       5       5  
Republic of the Congo
    21       13       19       11       13       12  
Democratic Republic of the Congo
    3       2       3       2       1       1  
                                                 
Total Africa
    433       352       414       328       116       142  
                                                 
Asia:
                                               
Indonesia
    243       235       199       182       268       319  
Thailand
    198       217       65       67       794       894  
Partitioned Zone (PZ)3
    105       106       101       103       21       20  
Kazakhstan
    69       66       42       41       161       153  
Bangladesh
    66       71       2       2       387       414  
Azerbaijan
    30       29       28       28       10       7  
Philippines
    27       26       4       5       137       128  
China
    19       22       17       19       16       22  
Myanmar
    13       15                   76       89  
                                                 
Total Asia
    770       787       458       447       1,870       2,046  
                                                 
Other:
                                               
United Kingdom
    110       106       73       71       222       208  
Australia
    108       96       35       34       434       376  
Denmark
    55       61       35       37       119       142  
Colombia
    41       35                   245       209  
Argentina
    38       44       33       37       27       45  
Trinidad and Tobago
    34       32       1             199       189  
Canada
    28       37       27       36       4       4  
Netherlands
    9       9       2       2       41       40  
Norway
    5       6       5       6       1       1  
Brazil
    2             2                    
                                                 
Total Other
    430       426       213       223       1,292       1,214  
                                                 
Total Consolidated Operations
    2,350       2,236       1,569       1,419       4,677       4,903  
Equity Affiliates4
    328       267       277       230       312       222  
                                                 
Total Including Affiliates5
    2,678       2,503       1,846       1,649       4,989       5,125  
                                                 
                                                 
1 2008 conformed to 2009 geographic presentation.
2 Excludes Athabasca oil sands production, net:
        26           27           26           27           —           —  
3 Located between Saudi Arabia and Kuwait.
4 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil (TCO) in Kazakhstan and Petroboscan, Petroindependiente and Petropiar in Venezuela.
5 Volumes include natural gas consumed in operations of 521 million and 520 million cubic feet per day in 2009 and 2008, respectively.
 
Worldwide oil-equivalent production, including volumes from oil sands (refer to footnote 2 above), was 2.7 million barrels per day, up about 7 percent from 2008. The increase was mostly associated with the start-up of the Blind Faith and Tahiti fields in the U.S. Gulf of Mexico in late 2008 and the second quarter 2009, respectively, the commencement of operations in the third quarter 2008 at the Agbami Field in Nigeria, and the expansion at Tengiz in Kazakhstan. Refer to the “Results of Operations” section beginning on page FS-6 for a detailed discussion of the factors explaining the 2007-2009 changes in production for crude oil and natural gas liquids, and natural gas.
 
The company estimates that its average worldwide oil-equivalent production in 2010 will be approximately 2.73 million barrels per day. This estimate is subject to many uncertainties, including quotas that may be imposed by OPEC, the price effect on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on the scope of company operations, delays in project start-ups, fluctuations in demand for natural gas in various markets, and production that may have to be shut in due to weather conditions, civil unrest,


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changing geopolitics or other disruptions to operations. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. 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.
 
 
Refer to Table IV on page FS-69 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 2009, 2008 and 2007.
 
 
The following table summarizes gross and net productive wells at year-end 2009 for the company and its affiliates:
 
 
                                 
    Productive2,3
    Productive2
 
    Oil Wells     Gas Wells  
    Gross     Net     Gross     Net  
 
United States
    49,761       32,720       11,567       5,671  
Africa
    2,292       766       17       7  
Asia
    10,580       9,106       2,336       1,510  
Other
    1,605       963       275       74  
                                 
Total Consolidated Companies
    64,238       43,555       14,195       7,262  
Equity in Affiliates
    1,133       403       7       2  
                                 
Total Including Affiliates
    65,371       43,958       14,202       7,264  
                                 
Multiple completion wells included above:
    929       596       390       313  
 
1 Includes wells producing or capable of producing and injection wells temporarily functioning as producing wells. Wells that produce both oil and gas are classified as oil wells.
2 Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned wells and the sum of the company’s fractional interests in gross wells.
3 Canadian synthetic oil is not produced through wells and therefore is not presented in the table above.
 
 
Refer to Table V beginning on page FS-69 for a tabulation of the company’s proved net crude-oil and natural-gas reserves by geographic area, at the beginning of 2007 and each year-end from 2007 through 2009, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2009. During 2009, the company provided crude-oil and natural-gas reserves estimates for 2008 to the Department of Energy, Energy Information Administration (EIA) that agree with the 2008 reserve volumes in Table V. This reporting fulfilled the requirement that such estimates be consistent with, and not differ more than 5 percent from, the information furnished to the Securities and Exchange Commission (SEC) in the company’s 2008 Annual Report on Form 10-K. During 2010, the company will file estimates of crude-oil and natural-gas reserves with the Department of Energy, EIA, consistent with the 2009 reserve data reported in Table V.


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The net proved-reserve balances at the end of each of the three years 2007 through 2009 are shown in the table below:
 
 
                         
    2009     2008     2007  
 
Liquids* — Millions of barrels
                       
Consolidated Companies
    4,610       4,735       4,665  
Affiliated Companies
    2,363       2,615       2,422  
Natural Gas — Billions of cubic feet
                       
Consolidated Companies
    22,153       19,022       19,137  
Affiliated Companies
    3,896       4,053       3,003  
Total Oil-Equivalent — Millions of barrels
                       
Consolidated Companies
    8,303       7,905       7,855  
Affiliated Companies
    3,012       3,291       2,922  
 
* Crude oil, condensate and natural gas liquids. 2009 liquids amount for consolidated companies includes 460 million barrels of synthetic oil produced from oil sands mining operations in Canada in accordance with the adoption of the new SEC definition of oil and gas producing activity.
 
 
At December 31, 2009, the company owned or had under lease or similar agreements undeveloped and developed crude-oil and natural-gas properties located throughout the world. The geographical distribution of the company’s acreage is shown in the following table.
 
Acreage1,2 at December 31, 2009
(Thousands of Acres)
 
                                                 
                Developed and
 
    Undeveloped3     Developed3     Undeveloped  
    Gross     Net     Gross     Net     Gross     Net  
 
United States
    4,679       3,708       6,139       3,769       10,818       7,477  
Africa
    9,663       5,705       2,499       917       12,162       6,622  
Asia
    38,370       18,491       5,313       2,742       43,683       21,233  
Other
    53,181       26,407       3,243       792       56,424       27,199  
                                                 
Total Consolidated Companies
    105,893       54,311       17,194       8,220       123,087       62,531  
Equity in Affiliates
    640       300       259       104       899       404  
                                                 
Total Including Affiliates
    106,533       54,611       17,453       8,324       123,986       62,935  
                                                 
 
1 Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage includes wholly owned interests and the sum of the company’s fractional interests in gross acreage.
2 Table does not include mining acreage associated with the synthetic oil production in Canada. At year-end 2009, undeveloped gross and net acreage totaled 235 and 31, respectively. Developed gross and net acreage totaled 35 and 7, respectively. Developed acreage is acreage associated with productive mines. Undeveloped acreage is acreage on which mines have not been established and that may contain undeveloped proved reserves.
3 Developed acreage is spaced or assignable to productive wells. Undeveloped acreage is acreage on which wells have not been drilled or completed to permit commercial production and that may contain undeveloped proved reserves. The gross undeveloped acres that will expire in 2010, 2011 and 2012 if production is not established by certain required dates are 13,526, 9,784 and 3,662, respectively.


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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 has no fixed and determinable delivery commitments to third-parties or affiliates.
 
Outside the United States, the company is contractually committed to deliver to third parties a total of 821 billion cubic feet of natural gas from 2010 through 2012 from Australia, Colombia, Denmark and the Philippines. The 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 Australia, Colombia, Denmark and the Philippines.
 
 
Refer to Table I on page FS-64 for details associated with the company’s development expenditures and costs of proved property acquisitions for 2009, 2008 and 2007.
 
The table below 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, 2009. 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 Completed1,2  
    at 12/31/093     2009     2008     2007  
    Gross     Net     Prod.     Dry     Prod.     Dry     Prod.     Dry  
 
United States
    47       22       582       3       846       4       875       5  
Africa
    6       2       40             33             43        
Asia
    38       22       580             665       1       597        
Other
    11       4       43             41             52        
                                                                 
Total Consolidated Companies
    102       50       1,245       3       1,585       5       1,567       5  
Equity in Affiliates
    1             6             16             3        
                                                                 
Total Including Affiliates
    103       50       1,251       3       1,601       5       1,570       5  
                                                                 
 
1 2008 and 2007 conformed to 2009 geographic presentation.
2 Indicates the fractional number of wells completed during the year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency.
3 Represents wells in the process of drilling, including wells for which drilling was not completed and which were temporarily suspended at the end of 2009. Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned wells and the sum of the company’s fractional interests in gross wells.


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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, 2009. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unproved areas and include delineation 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 Completed1,2  
    at 12/31/093     2009     2008     2007  
    Gross     Net     Prod.     Dry     Prod.     Dry     Prod.     Dry  
 
United States
    3       1       4       5       8       2       4       8  
Africa
    6       2       2       1       2       1       6       2  
Asia
    1             9       1       9       2       13       9  
Other
    4       3       5       4       44       2       43       6  
                                                                 
Total Consolidated Companies
    14       6       20       11       63       7       66       25  
Equity in Affiliates
                                               
                                                                 
Total Including Affiliates
    14       6       20       11       63       7       66       25  
                                                                 
 
1 2008 and 2007 conformed to 2009 geographic presentation.
2 Indicates the fractional number of wells completed during the year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency. Some exploratory wells are not drilled with the intention of producing from the well bore. In such cases, “completion” refers to the completion of drilling. Further categorization of productive or dry is based on the determination as to whether hydrocarbons in a sufficient quantity were found to justify completion as a producing well, whether or not the well is actually going to be completed as a producer.
3 Represents wells that are in the process of drilling but have been neither abandoned nor completed as of the last day of the year, including wells for which drilling was not completed and which were temporarily suspended at the end of 2009. Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned wells and the sum of the company’s fractional interests in gross wells.
 
Refer to Table I on page FS-64 for detail of the company’s exploration expenditures and costs of unproved property acquisitions for 2009, 2008 and 2007.
 
 
Chevron’s 2009 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-42.
 
The discussion that follows references the status of proved reserves recognition for significant long-lead-time projects not yet on production and for projects recently placed on production. Reserves are not discussed for recent discoveries that have yet to advance 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.


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(MAP)        
Chevron has production and exploration 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 gas business. The map at left indicates Chevron’s primary areas of production and exploration.
 
a)   United States
 
Upstream activities in the United States are concentrated in California, the Gulf of Mexico, Louisiana, Texas, New Mexico, the Rocky Mountains and Alaska. Average net oil-equivalent production in the United States during 2009 was 717,000 barrels per day.
 
In California, the company has significant production in the San Joaquin Valley. In 2009, average net oil-equivalent production was 211,000 barrels per day, composed of 191,000 barrels of crude oil, 91 million cubic feet of natural gas and 5,000 barrels of natural gas liquids. Approximately 84 percent of the crude-oil production is considered heavy oil (typically with API gravity lower than 22 degrees).
 
Average net oil-equivalent production during 2009 for the company’s combined interests in the Gulf of Mexico shelf and deepwater areas, and the onshore fields in the region was 243,000 barrels per day. The daily oil-equivalent production comprised 149,000 barrels of crude oil, 484 million cubic feet of natural gas and 14,000 barrels of natural gas liquids.
 
         
         
(MAP)        
During 2009, Chevron was engaged in various development and exploration activities in the deepwater Gulf of Mexico. The 75 percent-owned and operated Blind Faith development, which achieved first oil in the fourth quarter 2008, reached maximum total production of 70,000 barrels per day of oil-equivalent in 2009. Blind Faith has an estimated production life of 20 years.

At the 58 percent-owned and operated Tahiti Field, first oil was achieved in the second quarter 2009. Maximum total production of 135,000 barrels per day of oil-equivalent was achieved in the third quarter 2009. A second development phase is under evaluation, including additional development drilling and a probable waterflood, with a final investment decision planned formid-2010. The waterflood includes water injection topsides
equipment, subsea equipment and water injection wells. Tahiti has an estimated production life of 30 years. As of the end of 2009, proved reserves had been recognized for the first development phase of the Tahiti Field.
 
The company is participating in the ultra-deepwater Perdido Regional Development. The project encompasses the installation of a producing host facility to service multiple fields, including Chevron’s 33.3 percent-owned Great White, 60 percent-owned Silvertip and 57.5 percent-owned Tobago. Chevron has a 37.5 percent interest in the Perdido Regional Host. All of these fields and the production facility are partner-operated. Activities during 2009 included installation of the topsides on the spar, installation of umbilicals, hook-up and commissioning of the facility systems, and ongoing development drilling. First oil is expected in the first half of 2010, with the facility designed to handle 130,000 barrels of oil-equivalent per day. The project has an expected life of approximately 25 years. Proved reserves have been recognized for the project.


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The company has a 60 percent-owned and operated interest in Big Foot. Two successful appraisal wells have been drilled, the most recent in the first quarter 2009. The company also acquired the rights to an adjacent block during 2009. The project entered front-end engineering and design (FEED) in October 2009 and a final investment decision is expected in late 2010. Total maximum production from the project is expected to be 63,000 barrels of oil-equivalent per day. At the end of 2009, proved reserves had not been recognized.
 
The Caesar and Tonga partnerships for properties located in a number of blocks in the Green Canyon area have formed a unit agreement for the area, with Chevron having a 20.3 percent nonoperated working interest. A final investment decision on the joint Caesar-Tonga project was made in the first quarter 2009. Development plans include four wells and a subsea tie-back to a nearby third-party production facility. Two development sidetracks were completed during the year. Proved reserves have been recognized for the project and first oil is expected in 2011.
 
The Jack and St. Malo fields are located within 25 miles of each other and are being considered for joint development. Chevron has a 50 percent-owned interest in Jack and a 51 percent-owned interest in St. Malo, following the anticipated acquisition of an additional 9.8 percent equity interest in St. Malo in March 2010. Both fields are company operated. The project entered FEED in May 2009 and a final investment decision is expected in late 2010. The facility is planned to have an initial design capacity of 150,000 barrels of oil-equivalent per day and start-up is expected in 2014. At the end of 2009, proved reserves had not been recognized.
 
Deepwater exploration activities in 2009 and early 2010 included participation in 10 exploratory wells — five wildcat, three appraisal and two delineation. Exploratory work included the following:
 
  •   Buckskin — 55 percent-owned and operated. A successful wildcat discovery was announced in February 2009. The first appraisal well is scheduled to begin drilling in the second quarter 2010.
 
  •   Knotty Head — 25 percent nonoperated working interest. The first appraisal well began drilling in October 2009 at this 2005 discovery.
 
  •   Puma — 21.8 percent nonoperated working interest. An appraisal well completed drilling in early 2009. Leases were relinquished in mid-2009.
 
  •   Tubular Bells — 30 percent nonoperated working interest. Studies to screen and evaluate future development alternatives were continuing at the end of 2009.
 
At the end of 2009, the company had not recognized proved reserves for any of the exploration projects discussed above.
 
Besides the activities connected with the development and exploration projects in the Gulf of Mexico, the company also has contracted capacity of 1 billion cubic feet per day at the third-party Sabine Pass liquefied natural gas (LNG) regasification terminal in Louisiana. The 20-year capacity reservation agreement became effective in July 2009 and enables import of natural gas for the North America market. In September 2009, Chevron began to utilize a portion of the reserved capacity under this agreement.
 
Chevron has also contracted 1.6 billion cubic feet per day of capacity in a third-party pipeline system connecting the Sabine Pass LNG terminal to the natural-gas pipeline grid. The new pipeline, which was placed in service in July 2009, provides access to two major salt dome storage fields and 10 major interstate pipeline systems, including an interconnect with Chevron’s Sabine Pipeline, which connects to the Henry Hub. An interconnect to Chevron’s Bridgeline Pipeline is scheduled to be completed in the third quarter 2010. The Henry Hub interconnects to nine interstate and four intrastate pipelines and is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange.
 
Outside California and the Gulf of Mexico, the company manages operations across the mid-continental United States and Alaska. During 2009, the company’s U.S. production outside California and the Gulf of Mexico averaged 263,000 net oil-equivalent barrels per day, composed of 94,000 barrels of crude oil, 824 million cubic feet of natural gas and 31,000 barrels of natural gas liquids.
 
In the Piceance Basin in northwestern Colorado, additional production came on line in September 2009 from the company’s 100 percent-owned and operated natural-gas development. Development drilling, which began in 2007, surpassed 190 wells in 2009, with 81 completed wells available to supply natural gas to the central processing facility. Construction of compression and dehydration facilities to produce 65 million cubic feet per day of natural gas was completed in the third quarter 2009. Future work is expected to be completed in multiple stages. The full development plan includes drilling more than 2,000 wells from multi-well pads over the next 30 to 40 years. Proved reserves for subsequent stages of the project had not been recognized at year-end 2009.


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b)   Africa
 
In Africa, the company is engaged in exploration and production activities in Angola, Chad, Democratic Republic of the Congo, Nigeria and Republic of the Congo. Net oil-equivalent production in Africa averaged 433,000 barrels per day during 2009.
 
         
(MAP)        
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 2009 averaged 150,000 barrels of oil-equivalent per day.

The company operates the 39.2 percent-owned Block 0, which averaged 105,000 barrels per day of net liquids production in 2009. The Block 0 concession extends through 2030.

Initial production from the northern portion of the Mafumeira Field in Block 0 occurred in July 2009, and total maximum crude-oil production of 42,000 barrels per day was achieved in first quarter 2010. Front-end engineering and design (FEED) started in January 2010 on Mafumeira Sul, a project to develop the southern portion of the Mafumeira Field. A final investment decision is expected in 2011. Maximum production from Mafumeira Sul is expected to be 95,000 barrels of crude oil per day. At year-end 2009, no proved reserves had been recognized for this project.
 
In the Greater Vanza/Longui Area of Block 0, development concept selection was under way and continued into 2010. FEED is planned for 2011. FEED activities continued on the south extension of the N’Dola Field development. At year-end 2009, no proved reserves had been recognized for these projects.
 
Four gas management projects in Block 0 are expected to eliminate routine flaring of natural gas by injecting excess natural gas into various reservoirs. The Takula Flare and Relief Modification Project and the Cabinda Gas Plant Project entered service in June 2009 and December 2009, respectively. These projects are expected to reduce flaring by up to 60 million cubic feet per day. Work continued on the Nemba Enhanced Secondary Recovery and Flare Reduction Project and the Malongo Flare and Relief Modification Project, which are scheduled for start-up in the fourth quarter 2010 and in 2011, respectively.
 
Also in Block 0, a successful two-well exploration and appraisal program was completed. The exploration well was completed in March 2009, and the appraisal well was completed in May 2009. Drilling began on another exploration well in November 2009 and was completed in the first quarter 2010. The results are under evaluation.
 
In the 31 percent-owned Block 14, net production in 2009 averaged 33,000 barrels of liquids per day from the Benguela Belize — Lobito Tomboco development and the Kuito, Tombua and Landana fields. Development and production rights for the various fields in Block 14 expire between 2027 and 2029.
 
Development of the Tombua and Landana fields continued in 2009. First production occurred in August 2009 from new production facilities that were installed in late 2008. Proved developed reserves were recognized at start of production. Development drilling is expected to continue, with maximum total daily production of 100,000 barrels of crude oil anticipated in 2011.
 
During 2009, studies to evaluate development alternatives for the Lucapa Field continued. The project is expected to enter FEED in the fourth quarter 2010. A successful appraisal well was completed in the fourth quarter 2009 in the Malange area. As of the end of 2009, development of the Negage Field was suspended until cooperative arrangements between Angola and Democratic Republic of the Congo could be finalized. At the end of 2009, proved reserves had not been recognized for these projects.
 
The 39.2 percent-owned and operated Malongo Terminal Oil Export project was completed in November 2009. The new export system more than doubled export capacity from the area, which includes Blocks 0 and 14. In the 20 percent-owned Block 2 and the 16.3 percent-owned FST areas, combined production during 2009 averaged 3,000 barrels of net liquids per day.


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Equity Affiliate Operations: In addition to the exploration and producing activities in Angola, Chevron has a 36.4 percent ownership interest in the Angola LNG affiliate that began construction in early 2008 of an onshore natural gas liquefaction plant located in Soyo, Angola. The plant is designed to process more than 1 billion cubic feet of natural gas per day. Construction continued on schedule during 2009 with plant start-up scheduled for 2012. The life of the LNG plant is estimated to be in excess of 20 years. Proved reserves have been recognized for the producing operations associated with this project.
 
Angola — Republic of the Congo Joint Development Area: Chevron operates and holds a 31.3 percent interest in the Lianzi Development Area located between Angola and Republic of the Congo. In late 2008, the development project entered FEED, which continued through 2009. No proved reserves have been recognized for Lianzi.
 
Republic of the Congo: Chevron has a 31.5 percent nonoperated working interest in the Nkossa, Nsoko and Moho-Bilondo exploitation permits and a 29.3 percent nonoperated working interest in the Kitina exploitation permit, all of which are offshore. The development and production rights for Nkossa, Nsoko and Kitina expire in 2027, 2018 and 2019, respectively. Net production from the Republic of the Congo fields averaged 21,000 barrels of oil-equivalent per day in 2009.
 
In May 2009, a successful exploration well was drilled in the Moho-Bilondo exploitation permit area. Development alternatives were being evaluated during 2009. The Moho-Bilondo subsea development project, which started production in 2008, is expected to achieve maximum total production of 90,000 barrels of crude oil per day in the third quarter 2010. Chevron’s development and production rights for Moho-Bilondo expire in 2030.
 
Democratic Republic of the Congo: Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Daily net production in 2009 averaged 3,000 barrels of oil-equivalent.
 
Chad/Cameroon: Chevron participates in a project to develop crude-oil fields in southern Chad and transport the produced volumes by pipeline to the coast of Cameroon for export. Chevron has a 25 percent nonoperated working interest in the producing operations and an approximate 21 percent interest in two affiliates that own the pipeline. Average daily net production from the Chad fields in 2009 was 27,000 barrels of oil-equivalent. In September 2009, first production was achieved at the Timbre Field in the Doba area. The Chad producing operations are conducted under a concession that expires in 2030.
 
Libya: After an unsuccessful exploration well was completed, the company elected to relinquish its 100 percent interest in the onshore Block 177 exploration license in the fourth quarter 2009.
 
         
(MAP)        
Nigeria: Chevron holds a 40 percent interest in 13 concessions in the onshore and near-offshore region 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 deepwater offshore blocks. In 2009, the company’s net oil-equivalent production in Nigeria averaged 232,000 barrels per day, composed of 225,000 barrels of liquids and 48 million cubic feet of natural gas.

In deepwater Oil Mining Lease (OML) 127 and OML 128, the 68.2 percent-owned and operated Agbami Field reached maximum total liquids production of 250,000 barrels per day in August 2009, following completion of development drilling. In December 2009, a subsequent 10-well development program was initiated and is expected to offset field decline. The leases that contain the Agbami Field expire in 2023 and 2024.

Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the Bonga SW Field in offshore OML 118 share a common geologic structure and are planned to be jointly developed under a proposed unitization agreement. Work continued in 2009 on a final unitization agreement between Chevron and
partners in OML 118. At the end of 2009, no proved reserves were recognized for this project.


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Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery on OML 140. Development activities continued in 2009, with FEED expected to start after commercial terms are resolved. At the end of 2009, the company had not recognized proved reserves for this project.
 
The company also holds a 30 percent nonoperated working interest in the deepwater Usan project in OML 138. The development plans involve subsea wells producing to a floating production, storage and offloading vessel. Development drilling started in June 2009. Production start-up is scheduled for 2012, and maximum total production of 180,000 barrels of crude oil per day is expected to be achieved within one year of start-up. Total costs for the project are estimated at $8.4 billion. Usan has an estimated production life of 20 years. Proved reserves have been recognized for this project.
 
Chevron participated in one successful deepwater exploration well during 2009 in Oil Prospecting License (OPL) 223. The company has a 30 percent nonoperated working interest in the license. At the end of 2009, proved reserves had not been recognized for the exploration project.
 
In the Niger Delta, construction on the Phase 3A expansion of the Escravos Gas Plant (EGP) was completed in late 2009 and start of production is expected in March 2010. EGP Phase 3A scope includes offshore natural-gas gathering and compression infrastructure and the addition of a second natural-gas processing facility. The modifications are designed to increase processing capacity from 285 million to 680 million cubic feet of natural gas per day and increase LPG and condensate export capacity from 15,000 to 58,000 barrels per day. EGP Phase 3A is designed to process natural gas from the Meji, Delta South, Okan and Mefa fields. The anticipated life of EGP Phase 3A is 25 years. Phase 3B of the EGP project is designed to gather natural gas from eight offshore fields and to compress and transport natural gas to onshore facilities beginning in 2012. The engineering, procurement, construction, and installation contract for the pipelines was awarded and work commenced in late 2009. Proved reserves have been recognized for these projects.
 
The 40 percent-owned and operated Onshore Asset Gas Management project 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. Natural gas from these fields is sold in the Nigerian domestic gas market. The main on-site construction contracts are expected to be awarded in the second quarter 2010.
 
Refer to page 25 for a discussion of the planned gas-to-liquids facility at Escravos.
 
Equity Affiliate Operations: Chevron holds a 19.5 percent interest in the OKLNG Free Zone Enterprise (OKLNG) affiliate, which will operate the Olokola LNG project. OKLNG plans to build a multi-train natural-gas liquefaction facility and marine terminal located northwest of Escravos. At the end of 2009, timing of the final investment decision remains uncertain. The company has not recognized proved reserves associated with this project.
 
Refer to “Pipelines” under “Transportation Operations” beginning on page 26 for a discussion of the West African Gas Pipeline operations.


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c)  Asia
 
Major producing countries in Asia include Azerbaijan, Bangladesh, Indonesia, Kazakhstan, the Partitioned Zone located between Saudi Arabia and Kuwait, and Thailand. During 2009, net oil-equivalent production averaged 1,044,000 barrels per day in Asia.
 
         

(MAP)
       

Azerbaijan: Chevron holds a 10.3 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC), which produces crude oil in the Caspian Sea from the Azeri-Chirag-Gunashli (ACG) project. Chevron also has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, which transports AIOC production by pipeline from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities in Ceyhan, Turkey. (Refer to “Pipelines” under “Transportation Operations” beginning on page 26 for a discussion of BTC operations.)

In 2009, the company’s daily net production from AIOC averaged 30,000 barrels of oil-equivalent. The final investment decision on the next development phase is expected in the first half 2010. AIOC operations are conducted under a 30-year production-sharing contract (PSC) that expires in 2024.

Kazakhstan: Chevron holds a 20 percent nonoperated working interest in the Karachaganak project, which is being developed in phases. During 2009, Karachaganak net oil-equivalent production averaged 69,000 barrels per day, composed of 42,000 barrels of liquids and 161 million cubic feet of natural gas. In 2009, access to the Caspian Pipeline Consortium (CPC) and Atyrau-Samara (Russia) pipelines enabled approximately 184,000 barrels per day (33,000 net barrels) of Karachaganak liquids to be sold at world-market
prices. The remaining liquids were sold into Russian markets. During 2009, work continued on a fourth train that is designed to increase total export of processed liquids by 56,000 barrels per day. The fourth train is expected to start-up in 2011.
 
During 2009, Chevron and its partners continued to evaluate alternatives for a Phase III development of Karachaganak. Timing for the recognition of Phase III proved reserves is uncertain and depends on finalizing a project design and achieving project milestones. Karachaganak operations are conducted under a 40-year PSC that expires in 2038.
 
Equity Affiliate Operations: The company holds a 50 percent interest in Tengizchevroil (TCO), which is operating and developing the Tengiz and Korolev crude-oil fields, located in western Kazakhstan, under a 40-year concession that expires in 2033. Chevron’s net oil-equivalent production in 2009 from these fields averaged 274,000 barrels per day, composed of 226,000 barrels of crude oil and natural gas liquids and 289 million cubic feet of natural gas.
 
In 2009, TCO continued ramp-up of the Sour Gas Injection (SGI) and Second Generation Plant (SGP) facilities. The SGI facility injects approximately one-third of the sour gas separated from the crude oil back into the reservoir. The injected gas maintains higher reservoir pressure and displaces oil towards producing wells. TCO is evaluating options for another expansion project based on SGI/SGP technologies.
 
During 2009, 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 shipped via other export routes, which included shipment via tanker to Baku for transport by the BTC pipeline to Ceyhan or by rail to Black Sea ports. (Refer to “Pipelines” under “Transportation Operations” beginning on page 26 for a discussion of CPC operations.)


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Turkey: Chevron holds a 25 percent nonoperated working interest in the Silopi licenses in southeast Turkey, which is on trend with production in Iraq’s northern Zagros Fold Belt. An exploration well in the Lale prospect completed drilling in the first quarter 2010, and is under evaluation.
 
Bangladesh: Chevron holds interests in three operated PSCs covering onshore Blocks 12, 13 and 14 and offshore Block 7. The company has a 98 percent interest in Blocks 12, 13 and 14. Government approval of a 2009 farm-out in Block 7 was received in February 2010, reducing the company’s interest from 88 percent to 43 percent. The farm-out was to GS Caltex, a 50 percent-owned affiliate of the company. Net oil-equivalent production from these operations in 2009 averaged 66,000 barrels per day, composed of 387 million cubic feet of natural gas and 2,000 barrels of liquids. In 2009, a final investment decision was achieved after the government approved the development of a compression project that is expected to support additional production starting in 2012 from the Bibiyana, Jalalabad and Moulavi Bazar natural-gas fields. Proved reserves have been recognized for this project. The government also approved an amendment to the PSC for Blocks 13 and 14 that allows the company to acquire additional 3-D seismic over the Jalalabad Field. Also in 2009, the company acquired seismic data on Block 7. Evaluation and data processing is under way, and an exploration well is planned to be completed by 2011.
 
Cambodia: Chevron operates the 1.2 million-acre (4,709 sq-km) Block A, located offshore in the Gulf of Thailand, and expects to reduce its ownership to 30 percent pending government approval of the farm-out that is anticipated in the second quarter 2010. In 2009, commercial evaluation of the prospects continued. The company was granted an extension for the Block A exploration period to the third quarter 2010 in exchange for the obligation to drill three exploration wells. Information gained from the drilling program is expected to provide improved definition of the resource in the block. Proved reserves had not been recognized as of the end of 2009.
 
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 offshore in the Andaman Sea. The company also has a 28.3 percent interest in a pipeline company that transports the natural gas from Yadana to the Myanmar-Thailand border for delivery to power plants in Thailand. Most of the natural gas is purchased by Thailand’s PTT Public Company Limited (PTT). The company’s average net natural gas production in 2009 was 76 million cubic feet per day. During 2009, the platform for a compression project was completed. Project start-up is expected in 2011.
 
         

(MAP)
       

Thailand: Chevron has operated and nonoperated working interests in several different offshore blocks. The company’s net oil-equivalent production in 2009 averaged 198,000 barrels per day, composed of 65,000 barrels of crude oil and condensate and 794 million cubic feet of natural gas. All of the company’s natural-gas production is sold to PTT under long-term sales contracts.

Operated interests are in Pattani and other fields with ownership interests ranging from 35 percent to 80 percent in Blocks 10 through 13, B12/27, B8/32, 9A, G4/43 and G4/48. Blocks B8/32 and 9A produce crude oil and natural gas from eight operating areas, and Blocks 10 through 13 and B12/27 produce crude oil, condensate and natural gas from 16 operating areas.
Chevron has a 16 percent nonoperated working interest in Blocks 14A, 15A, 16A, G9/48 and G8/50, known collectively as the Arthit Field.
 
During 2009, construction at the 69.8 percent-owned and operated Platong Gas II project continued. The project is designed to add 420 million cubic feet per day of processing capacity in 2012. Proved reserves have been recognized for this project. Concessions for Blocks 10 through 13 expire in 2022.
 
During 2009, 14 exploration wells were drilled in the Gulf of Thailand, 13 were successful and one nonoperated well in the Arthit Field was unsuccessful. Two 3-D seismic surveys and geological studies for Block G4/50 were also completed in 2009. At the end of 2009, proved reserves had not been recognized for these activities. Three exploratory wells in Block G4/50 are planned for the second quarter 2010. For Blocks G6/50 and G7/50, one exploration well is scheduled in each block for completion by the third quarter 2010. In addition, Chevron holds exploration interests in a number of blocks that are currently inactive, pending resolution of border issues between Thailand and Cambodia.


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Vietnam: The company operates off the southwest coast and has a 42.4 percent interest in a PSC that includes Blocks B and 48/95, and a 43.4 percent interest in another PSC for Block 52/97. In August 2009, Chevron reduced its ownership interest in a third operated PSC to 20 percent in Block B122 offshore eastern Vietnam. No production occurred in these areas during 2009.
 
In the blocks off the southwest coast, the Vietnam Gas Project is aimed at developing an area in the Malay Basin to supply natural gas to state-owned Petrovietnam. The project includes installation of wellhead and hub platforms, a floating storage and offloading vessel, field pipelines and a central processing platform. The project is expected to enter front-end engineering and design (FEED) in the first quarter 2010, and a final investment decision is expected in 2011. Maximum total production is planned to be about 500 million cubic feet of natural gas per day. At the end of 2009, proved reserves had not been recognized for this project.
 
In conjunction with the Vietnam Gas Project, a Petrovietnam-operated pipeline will be required to support the offshore development. Chevron will have a 28.7 percent interest in the pipeline, which is planned to transport natural gas from the offshore development to customers in southern Vietnam.
 
During the year, the company continued to analyze well results and seismic processing from Block B and Block 52/97. In Block 122, 2-D seismic data processing and geologic studies were completed. An exploration well is planned for 2011. Proved reserves had not been recognized as of the end of 2009. Future activity in Block 122 may be affected by an ongoing territorial dispute between Vietnam and China.
 
         
(MAP)        
China: Chevron has one operated and three nonoperated working interests in several areas. Net oil-equivalent production from the nonoperated areas in 2009 averaged 19,000 barrels per day, composed of 17,000 barrels of crude oil and condensate and 16 million cubic feet of natural gas.

The company holds a 49 percent-owned and operated interest in the Chuandongbei area in the onshore Sichuan Basin, where the company entered into a 30-year PSC effective February 2008 to develop natural-gas resources. Project plans included two sour-gas purification plants with an aggregate design capacity of 740 million cubic feet per day. During 2009, general infrastructure for the plant site and well pads progressed. Development drilling and the construction and installation of additional processing facilities and gathering systems are expected to start in 2010. Proved reserves have been recognized for this project. The PSC for Chuandongbei expires in 2038.

In the South China Sea, the company has nonoperated working interests of 32.7 percent in Blocks 16/08 and 16/19 located in the Pearl River Delta Mouth Basin, 24.5 percent in the QHD-32-6 Field in Bohai Bay, and 16.2 percent in the unitized and producing BZ 25-1 and BZ 19-4 crude-oil fields in Bohai Bay Block 11/19. In
November 2009, a storm damaged the floating production, storage and offloading (FPSO) vessel utilized by the company’s nonoperated assets in Block 11/19. Temporary and permanent recovery options are under development and production is expected to fully resume in 2012.
 
The joint development of the HZ25-3 and HZ25-1 crude-oil fields in Block 16/19 continued through the end of 2009. First production was delayed from the third quarter 2009 and is expected to be fully restored in the fourth quarter 2010 following damage to the FPSO vessel caused by a typhoon that struck the area in September 2009.
 
In 2009, Chevron relinquished its nonoperated working interest in four exploration blocks in the Ordos Basin. Government approval is expected in mid-2010.


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(MAP)         Indonesia: Chevron’s operated interests in Indonesia are managed by several wholly owned subsidiaries, including PT Chevron Pacific Indonesia (CPI). CPI holds operated interests of 100 percent in the Rokan and Siak PSCs and 90 percent in the MFK (Mountain Front Kuantan) PSC. Other subsidiaries operate four PSCs in the Kutei Basin, located offshore East Kalimantan, and one PSC in the East Ambalat Block, located offshore northeast Kalimantan. These interests range from 80 percent to 100 percent. Chevron also has nonoperated working interests in a joint venture in Block B in the South Natuna Sea and in the NE Madura III Block inthe East Java Sea Basin. Chevron’s interests in these PSCs range from 25 percent to 40 percent.
 
The company’s net oil-equivalent production in 2009 from all of its interests in Indonesia averaged 243,000 barrels per day. The daily oil-equivalent rate comprised 199,000 barrels of liquids and 268 million cubic feet of natural gas. The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood operation since 1985 and is one of the world’s largest steamflood developments. The North Duri Development is divided into multiple expansion areas. The first expansion in Area 12 started steam injection in June 2009. Maximum total daily production from Area 12 is estimated at 34,000 barrels of crude oil in 2012. A final investment decision regarding North Duri Area 13 is expected by year-end 2010. The Rokan PSC expires in 2021.
 
Chevron advanced its development plans for the Gendalo and Gehem deepwater natural-gas fields located in the Kutei Basin. FEED started in December 2009, with completion dependent upon achieving project milestones and receipt of government approvals. The Bangka deepwater natural-gas project was progressed during the year under a revised, lower-cost development plan. The project is expected to enter FEED in the second quarter 2010. Under the terms of the PSCs for both projects, the company’s 80 percent-owned and operated interest is expected to be reduced to 72 percent in 2010 with the farm-in of an Indonesian company. At the end of 2009, the company had not recognized proved reserves for either of these projects.
 
Also in the Kutei Basin, first production at the Seturian Field occurred in September 2009, which is providing natural gas to a state-owned refinery. During 2009, evaluation of the 50 percent-owned and operated Sadewa project in the Kutei Basin was suspended.
 
A drilling campaign continued through 2009 in South Natuna Sea Block B to provide additional supply for long-term natural-gas sales contracts with additional development drilling planned for 2010. The North Belut development project achieved first production in November 2009. The South Belut development project was under review during the year.
 
A two-well exploration program was conducted in the Central Sumatra Basin in 2009. One commercial discovery was made in the Rokan Block, and a second well in the Siak Block resulted in a dry hole. Chevron’s working interests in two exploration blocks in western Papua, West Papua I and West Papua III, are expected to be reduced to 51 percent interests in 2010. Completion of geological studies for those blocks was ongoing at year-end 2009, and 2-D seismic acquisition is planned for the second half 2010.
 
In West Java, Chevron operates the wholly owned Salak geothermal field with a total power-generation capacity of 377 megawatts. Also in West Java, Chevron holds a 95 percent interest in a power generation company that operates the Darajat geothermal contract area with a total capacity of 259 megawatts. Chevron also operates a 95 percent-owned 300-megawatt cogeneration facility in support of CPI’s operation in North Duri, Sumatra.
 


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(MAP)        
Partitioned Zone (PZ): Chevron holds a 30-year agreement with the Kingdom of Saudi Arabia to operate on behalf of the Saudi government its 50 percent interest in the petroleum resources of the onshore area of the PZ between Saudi Arabia and Kuwait. Under the agreement, the company has rights to this 50 percent interest in the hydrocarbon resource and pays royalty and taxes on the associated volumes produced until 2039.

During 2009, the company’s average net oil-equivalent production was 105,000 barrels per day, composed of 101,000 barrels of crude oil and 21 million cubic feet of natural gas. In June 2009, steam injection was initiated in the second phase of a steamflood pilot project.
The pilot is an application of steam injection into a carbonate reservoir and, if successful, could significantly increase heavy oil recovery. The Central Gas Utilization Project was initiated in 2009 to assess alternatives to increase natural-gas utilization and eliminate routine flaring. A final investment decision is expected in 2011. No reserves have been recognized for these projects.
 
Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural-gas field located 50 miles (80 km) offshore Palawan Island. Net oil-equivalent production in 2009 averaged 27,000 barrels per day, composed of 137 million cubic feet of natural gas and 4,000 barrels of condensate. Chevron also develops and produces geothermal resources under an agreement with the Philippine government. Chevron expects to sign a new 25-year contract with the government by the end of 2010 to operate the steam fields, which supply geothermal resources to the 637 megawatt geothermal facilities.
 
 
“Other” is composed of Australia, Argentina, Brazil, Colombia, Trinidad and Tobago, Venezuela, Canada, Greenland, Denmark, Faroe Islands, the Netherlands, Norway, Poland and the United Kingdom. Net oil-equivalent production from countries included in this section averaged 484,000 barrels per day during 2009. In addition, the company’s share of production from oil sands (for upgrading into synthetic oil) from the Athabasca Oil Sands Project in Canada was 26,000 barrels per day.
 
         
(map)           
Australia: During 2009, the average net oil-equivalent production from Chevron’s interests in Australia was 108,000 barrels per day, composed of 35,000 barrels of liquids and 434 million cubic feet of natural gas.

Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture offshore Western Australia. Daily net production from the project during 2009 averaged 26,000 barrels of crude oil and condensate, 433 million cubic feet of natural gas, and 5,000 barrels of LPG. Approximately 70 percent of the natural gas was sold in the form of LNG to major utilities in Japan, South Korea and China, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market.

The NWS Venture continues to progress two major capital projects that achieved final investment decision in 2008. Fabrication of platform topsides for the North Rankin 2 project commenced in June 2009. The project is designed to recover remaining low-pressure natural gas from the North Rankin and Perseus natural-gas fields to meet gas supply needs and includes necessary tie-ins to, and refurbishment of, the North Rankin A platform. Upon completion, both platforms are


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designed to be operated as a single integrated facility. The project is scheduled to start production in 2013. Proved reserves have been recognized for the project.
 
The NWS Venture is also advancing plans to extend the period of crude-oil production. The NWS Oil Redevelopment Project is designed to replace the present floating production, storage and offloading vessel and a portion of existing subsea infrastructure that services production from the Cossack, Hermes, Lambert and Wanaea offshore fields. In 2009, work commenced on conversion of the replacement vessel. The project is expected to start-up in early 2011 and extend production past 2020. The concession for the NWS Venture expires in 2034.
 
On Barrow and Thevenard islands off the northwest coast of Australia, Chevron operates crude-oil producing facilities that had combined net production of 4,000 barrels per day in 2009. Chevron’s interests in these operations are 57.1 percent for Barrow and 51.4 percent for Thevenard.
 
Also off the northwest coast of Australia, Chevron holds significant equity interests in the large natural-gas resource of the Greater Gorgon Area. The company initially held a 50 percent ownership interest across most of the area and is the operator of the Gorgon Project. Chevron and its joint-venture partners are proceeding with the combined development of Gorgon and nearby natural-gas fields as one large-scale project. Environmental approval from the Australian Commonwealth Government was issued in August 2009. In September 2009, the company announced the final investment decision and total estimated project costs for the first phase of development of $37 billion (AU$ 43 billion). The project’s scope includes a three-train, 15 million-metric-ton-per-year LNG facility; a carbon sequestration project; and a domestic natural-gas plant. Natural gas for the project is expected to be supplied from the Gorgon and Io/Jansz fields.
 
In 2009, long-term, binding agreements were finalized with four Asian customers for the delivery of about 4.4 million metric tons per year of LNG from the Gorgon Project. Equity sales agreements with three of the customers reduced Chevron’s interest in the project to 47.3 percent at the end of 2009. Nonbinding Heads of Agreements (HOA) for delivery of an additional 2.1 million metric tons per year of LNG were also signed with three additional Asian customers in 2009 and early 2010. Negotiations continue to finalize binding sales agreements, which would bring LNG delivery commitments to a combined total of about 90 percent of Chevron’s share of LNG from the project. During 2009, the company recognized proved reserves for the Greater Gorgon Area fields included in the project. First production of natural gas from these fields is expected in 2014. The project’s estimated economic life exceeds 40 years from the time of start-up.
 
Development of the company’s majority-owned and operated Wheatstone and Iago fields, located offshore Western Australia, continued with the project entering front-end engineering and design (FEED) in July 2009. Chevron operates the project and plans to supply natural gas to its 75 percent-owned and operated LNG facilities from two 100 percent-owned licenses comprising the majority of the Wheatstone Field and part of the nearby Iago Field. In October 2009, agreements were signed with two companies to join the Wheatstone Project as combined 25 percent LNG facility owners and suppliers of natural gas for the project’s first two LNG trains. In December 2009 and January 2010, nonbinding HOAs were signed with two Asian customers to take delivery of 4.9 million tons of LNG per year from the project, representing about 60 percent of the total LNG available from the foundation project. In addition, under these same HOAs the parties would acquire a combined 16.8 percent nonoperated working interest in the Wheatstone Field licenses and a 12.6 percent interest in the foundation natural-gas processing facilities at the final investment decision. At the end of 2009, the company had not recognized proved reserves for this project.
 
In the Browse Basin, the company continued engineering and survey work on two potential development concepts for the Brecknock, Calliance and Torosa fields. At the end of 2009, proved reserves had not been recognized.
 
In May 2009, the company announced the successful completion of a well at the Clio prospect to further explore and appraise the 66.7 percent-owned Block WA-205-P. In 2009 and early 2010, the company also announced natural-gas discoveries at the Kentish Knock prospect in the 50 percent-owned Block WA-365-P, the Achilles and Satyr prospects in the 50 percent-owned Block WA-374-P and the Yellowglen prospect in the 50 percent-owned WA-268-P Block. All prospects are Chevron-operated. At the end of 2009, proved reserves had not been recognized.
 


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(MAP)        
Argentina: Chevron holds operated interests in eight concessions in the Neuquen Basin. Working interests range from 18.8 percent to 100 percent. Net oil-equivalent production in 2009 averaged 38,000 barrels per day, composed of 33,000 barrels of crude oil and natural gas liquids and 27 million cubic feet of natural gas. The company also holds a 14 percent interest in the Oleoductos del Valle S.A. pipeline. In 2009, Chevron sold its oil and gas concession in the Austral Basin and its interest in the Confluencia Field in the Neuquen Basin.

Brazil: Chevron holds working interests in three deepwater blocks in the Campos Basin. Chevron also holds a nonoperated working interest in one block in the Santos Basin. Net oil-equivalent production in 2009 averaged 2,000 barrels per day.

The Frade Field, located in the Campos Basin, achieved first oil in June 2009. Chevron is the operator and has a 51.7 percent interest in the field. Additional development drilling is under way, with an estimated maximum total production of 72,000 oil-equivalent barrels per day. The concession that includes the Frade project expires in 2025.

In the partner-operated Campos Basin Block BC-20, two areas — 37.5 percent-owned Papa-Terra and 30 percent-owned Maromba — were retained for developmentfollowing the end of the exploration phase of this block. The Papa-Terra project progressed through FEED, and a
final investment decision was made in January 2010. The project operator estimates total costs of $5.2 billion and expects first production in 2013. The facility is expected to be capable of producing up to 140,000 barrels of crude oil per day. Evaluation of design options for Maromba continued into 2010. At the end of 2009, proved reserves had not been recognized for these projects.
 
In the Santos Basin, evaluation of investment options continued into 2010 for the 20 percent-owned and partner-operated Atlanta and Oliva fields. At the end of 2009, proved reserves had not been recognized for these fields.
 
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 from a fixed-fee Build-Operate-Maintain-Transfer agreement based on prior Chuchupa capital contributions. Daily net production averaged 245 million cubic feet of natural gas in 2009.
 
Trinidad and Tobago: Company interests include 50 percent ownership in three partner-operated blocks in the East Coast Marine Area offshore Trinidad, which includes the Dolphin and Dolphin Deep producing natural-gas fields and the Starfish discovery. Chevron also holds a 50 percent operated interest in the Manatee area of Block 6(d). Net production in 2009 averaged 199 million cubic feet of natural gas per day. Incremental production associated with a new domestic sales agreement commenced at Dolphin in the third quarter 2009.
 
Venezuela: The company operates in two exploratory blocks offshore Plataforma Deltana, with working interests of 60 percent in Block 2 and 100 percent in Block 3. Chevron also holds a 100 percent operated interest in the Cardon III exploratory block, located north of Lake Maracaibo in the Gulf of Venezuela. Petróleos de Venezuela, S.A. (PDVSA), Venezuela’s national crude-oil and natural-gas company, has the option to increase its ownership in each of the three company-operated blocks up to 35 percent upon declaration of commerciality. In February 2010, a Chevron-led consortium was selected to participate in a heavy-oil project composed of three blocks in the Orinoco Oil Belt of eastern Venezuela. The consortium is expected to acquire a 40 percent interest in the project, with PDVSA holding the remaining interest.
 
The Loran Field in Block 2 is projected to provide the initial supply of natural gas for Delta Caribe LNG (DCLNG) Train 1, Venezuela’s first LNG train. A DCLNG framework agreement was signed in 2008, which provides Chevron with

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a 10 percent nonoperated interest in the first train and the associated offshore pipeline. An interim operating agreement governing activities prior to a final investment decision was signed by Chevron and its Train 1 partners in March 2009. In May 2009, the company relinquished part of Block 3 and retained the portion containing the 2005 Macuira natural-gas discovery. An unsuccessful exploration well was drilled in the Cardon III block in 2009. The company plans to continue to evaluate exploration potential in the Cardon III block in 2010. At the end of 2009, proved reserves had not been recognized in these exploratory blocks.
 
Equity Affiliate Operations: Chevron also holds interests in two affiliates located in western Venezuela and in one 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 average net oil-equivalent production during 2009 from these operations was 54,000 barrels per day, composed of 51,000 barrels of crude oil and natural gas liquids and 23 million cubic feet of natural gas.
 
         
(MAP)        
Canada: Company activities in Canada include nonoperated working interests of 26.9 percent in the Hibernia Field and 26.6 percent in the Hebron Field, both offshore eastern Canada, and 20 percent in the Athabasca Oil Sands Project (AOSP) and operated interests of 60 percent in the Ells River Oil Sands Project. Excluding volumes mined at AOSP, average net oil-equivalent production during 2009 was 28,000 barrels per day, composed of 27,000 barrels of crude oil and natural gas liquids and 4 million cubic feet of natural gas.

Substantially all of this production was from the Hibernia Field, where the working interest owners are also pursuing development of the Hibernia Southern Extension (HSE). Development of the HSE nonunitized area was approved by the provincial regulator in 2009, and the first producing well for the project was completed at year-end.
In February 2010, binding agreements were signed with the Government of Newfoundland and Labrador on the development of the HSE unitized area, providing Chevron with a 23.6 percent nonoperated working interest in the unitized area.
 
For Hebron, agreements were reached during 2008 with the Government of Newfoundland and Labrador that allow development activities to begin. At the end of 2009, proved reserves had not been recognized for this project.
 
At AOSP, the company’s production from oil sands (for upgrading into synthetic oil) averaged 26,000 barrels per day during 2009. The first phase of an expansion project is under way and is expected to increase total production from oil sands by 100,000 barrels per day. The expansion would increase total AOSP design capacity to more than 255,000 barrels per day in late 2010. The projected cost of this expansion is $14.3 billion.
 
The Ells River project consists of heavy-oil leases of more than 85,000 acres (344 sq km). The area contains significant volumes with potential for recovery by using Steam Assisted Gravity Drainage, an industry-proven technology that employs steam and horizontal drilling to extract the production from oil sands through wells rather than through mining operations. Additional field appraisal activity is not planned in the near-term. At the end of 2009, proved reserves had not been recognized.
 
The company also holds exploration leases in the Mackenzie Delta and Beaufort Sea region, including a 34 percent nonoperated working interest in the offshore Amauligak discovery. Three exploration wells were drilled on company leases in the Mackenzie Delta region in 2009, and assessment of development concept alternatives for Amauligak continues. The company holds additional exploration acreage in eastern Labrador and the Orphan Basin. In 2009, the company was also successful in acquiring a western Canada lease position to explore for shale gas. At the end of 2009, proved reserves had not been recognized for any of these areas.


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Greenland: Processing of the 2-D seismic survey acquired over License 2007/26 in Block 4 offshore West Greenland in 2008 continued in 2009, and evaluation will commence in the first-half 2010. Chevron has a 29.2 percent nonoperated working interest in this exploration license.
 
         

(MAP)
       

Denmark: Chevron has a 15 percent working interest in the partner-operated Danish Underground Consortium (DUC), which produces crude oil and natural gas from 15 fields in the Danish North Sea. Net oil-equivalent production in 2009 from DUC averaged 55,000 barrels per day, composed of 35,000 barrels of crude oil and 119 million cubic feet of natural gas. DUC development activity in the region includes the ongoing Halfdan Phase IV project, which achieved first production in July 2009.

Faroe Islands: Chevron withdrew from License 008 in 2009, but continues to assess exploration opportunities in the area.

Netherlands: Chevron operates and holds interests ranging from 34.1 percent to 80 percent in eight blocks in the Dutch sector of the North Sea. In 2009, the company’s net oil-equivalent production from the five producing blocks was 9,000 barrels per day, composed of 2,000 barrels of crude oil and 41 million cubic feet of natural gas. In 2009 Chevron divested its 48 percent interest in the L11/b license.
Norway: The company holds a 7.6 percent interest in the partner-operated Draugen Field. The company’s net production averaged 5,000 barrels of oil-equivalent per day during 2009. In 2009, Chevron was awarded a 40 percent working interest as operator of the exploration license PL 527 in the deepwater portion of the Norwegian Sea. Data acquisition was completed on a 2-D seismic survey, and evaluation is under way.
 
Poland: In December 2009, Chevron was awarded three five-year exploration licenses in the Zwierzyniec, Kransnik and Frampol concessions, and in February 2010, Chevron acquired the exploration rights to the Grabowiec concession. Chevron has a 100 percent-owned and operated interest in these four concessions to explore for shale gas.
 
United Kingdom: The company’s average net oil-equivalent production in 2009 from 10 offshore fields was 110,000 barrels per day, composed of 73,000 barrels of crude oil and natural gas liquids and 222 million cubic feet of natural gas. Most of the production was from 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.
 
Evaluation of development alternatives continued during 2009 for the 19.4 percent-owned and partner-operated Clair Phase 2 project west of the Shetland Islands. In the 40 percent-owned and operated Rosebank/Lochnagar area northwest of the Shetland Islands, an exploration well in Rosebank North was completed in the second quarter 2009 and an appraisal well in Rosebank/Lochnagar was completed in the third quarter 2009. Also northwest of the Shetland Islands, a three-well exploration and appraisal drilling program was completed in 2009 at the Cambo prospect. Technical studies have commenced to select a preferred development alternative. Additional exploration drilling in the region is expected to occur in the second-half 2010. As of the end of 2009, proved reserves had not been recognized for any of these prospects.
 
In February 2010, the company sold its 10 percent nonoperated interest in the Laggan/Tormore discovery.
 
 
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.


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During 2009, U.S. and international sales of natural gas were 5.9 billion and 4.1 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, Kazakhstan, Indonesia, Latin America, the Philippines, Thailand and the United Kingdom.
 
U.S. and international sales of natural gas liquids were 161 thousand and 111 thousand barrels per day, respectively, in 2009. Substantially all of the international sales of natural gas liquids are from company operations in Africa, Australia and Indonesia.
 
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 8 for information related to the company’s delivery commitments for the sale of crude oil and natural gas.
 
Downstream — Refining, Marketing and Transportation
 
 
At the end of 2009, the company had a refining network capable of processing more than 2 million barrels of crude oil per day. Operable capacity at December 31, 2009, and daily refinery inputs for 2007 through 2009 for the company and affiliate refineries were as follows:
 
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, 2009                    
              Operable
    Refinery Inputs  
Locations   Number     Capacity     2009     2008     2007  
 
Pascagoula
  Mississippi     1       330       345       299       285  
El Segundo
  California     1       269       247       263       222  
Richmond
  California     1       243       218       237       192  
Kapolei
  Hawaii     1       54       49       46       51  
Salt Lake City
  Utah     1       45       40       38       42  
Perth Amboy1
  New Jersey     1       80             8       20  
                                             
Total Consolidated Companies — United States
    6       1,021       899       891       812  
                                         
Pembroke
  United Kingdom     1       210       205       203       212  
Cape Town2
  South Africa     1       110       72       75       72  
Burnaby, B.C.
  Canada     1       55       49       36       49  
                                             
Total Consolidated Companies — International
    3       375       326       314       333  
Affiliates3
  Various Locations     8       762       653       653       688  
                                             
Total Including Affiliates — International
    11       1,137       979       967       1,021  
                                         
Total Including Affiliates — Worldwide
      17         2,158         1,878         1,858         1,833  
                                         
 
1 Perth Amboy has been idled since early 2008 and is operated as a terminal.
2 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 2010.
3 Includes 3,000, 6,000 and 35,000 barrels per day of refinery inputs in 2009, 2008 and 2007, respectively, for interests in refineries that were sold during those periods.
 
Average crude oil distillation capacity utilization during 2009 was 91 percent, compared with 87 percent in 2008, largely a result of improved utilization at the refineries in Mississippi, Canada and Thailand. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 96 percent in 2009, compared with 95 percent in 2008, and cracking and coking capacity utilization averaged 85 percent and 86 percent in 2009 and 2008, respectively. Cracking and coking units are the primary facilities used in fuel refineries to convert heavier feedstocks into gasoline and other light products.
 
The company’s refineries in the United States, the United Kingdom, Canada, South Africa and Australia produce low-sulfur fuels. During 2009, GS Caltex, the company’s 50 percent-owned affiliate, continued construction on a new heavy-oil hydrocracker designed to increase high-value product yield and lower feedstock costs at the Yeosu, South Korea


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complex. Project completion is expected in 2010. Modifications were completed in 2009 that enable the company’s 50 percent-owned Singapore Refining Company’s refinery to meet regional specifications for clean diesel fuels.
 
At the Pascagoula Refinery, construction progressed on a continuous catalytic reformer that is expected to improve refinery reliability. Planning continued for a premium base-oil facility at the company’s Pascagoula Refinery. The facility is being designed to produce approximately 25,000 barrels per day of premium base oil for use in manufacturing high-performance lubricants, such as motor oils for consumer and commercial applications. At the refinery in El Segundo, California, design, engineering and construction work advanced during 2009 on projects that will reduce feedstock costs and improve yields.
 
At the beginning of 2009, Chevron held a 5 percent interest in Reliance Petroleum Limited, a company formed by Reliance Industries Limited to construct a new refinery in Jamnagar, India. During the year, the company sold its 5 percent interest to Reliance Industries Limited.
 
Chevron processes imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 85 percent and 88 percent of Chevron’s U.S. refinery inputs in 2009 and 2008, respectively.
 
 
In Nigeria, Chevron and the Nigerian National Petroleum Corporation are developing a 33,000 barrel-per-day gas-to-liquids facility at Escravos designed to process 325 million cubic feet per day of natural gas supplied from the Phase 3A expansion of the Escravos Gas Plant (EGP). At the end of 2009, construction was under way with two gas-to-liquids reactors and the process modules delivered to the site. Chevron has a 75 percent interest in the plant, which is expected to be operational by 2012. The estimated cost of the plant is $5.9 billion. Refer also to page 14 for a discussion on the EGP Phase 3A expansion.
 
 
The company markets petroleum products under the principal brands of “Chevron,” “Texaco” and “Caltex” throughout much of the world. The table below identifies the company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ended December 31, 2009.
 
Refined Products Sales Volumes
(Thousands of Barrels per Day)
 
                         
    2009     2008     2007  
 
United States
                       
Gasolines
    720       692       728  
Jet Fuel
    254       274       271  
Gas Oils and Kerosene
    226       229       221  
Residual Fuel Oil
    110       127       138  
Other Petroleum Products1
    93       91       99  
                         
Total United States
    1,403       1,413       1,457  
                         
International2
                       
Gasolines
    555       589       581  
Jet Fuel
    264       278       274  
Gas Oils and Kerosene
    647       710       730  
Residual Fuel Oil
    209       257       271  
Other Petroleum Products1
    176       182       171  
                         
Total International
    1,851       2,016       2,027  
                         
Total Worldwide2
    3,254       3,429       3,484  
                         
 
                             
1
  Principally naphtha, lubricants, asphalt and coke.                        
2
  Includes share of equity affiliates’ sales:     516       512       492  
 


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In the United States, the company markets under the Chevron and Texaco brands. At year-end 2009, the company supplied directly or through retailers and marketers approximately 9,600 Chevron- and Texaco-branded motor vehicle service stations, primarily in the mid-Atlantic, southern and western states. Approximately 500 of these outlets are company-owned or -leased stations. The company plans to discontinue, by mid-2010, sales of Chevron- and Texaco-branded motor fuels in the mid-Atlantic and other eastern states, where the company sold to retail customers through approximately 1,100 stations and to commercial and industrial customers through supply arrangements. Sales in these markets represent approximately 8 percent of the company’s total U.S. retail fuels sales volumes. Additionally, in January 2010, the company sold the rights to the Gulf trademark in the United States and its territories that it had previously licensed for use in the U.S. Northeast and Puerto Rico.
 
Outside the United States, Chevron supplied directly or through retailers and marketers approximately 12,400 branded service stations, including affiliates. In British Columbia, Canada, the company markets under the Chevron brand. The company markets in the United Kingdom, Ireland, Latin America and the Caribbean 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 affiliate, GS Caltex, and in Australia through its 50 percent-owned affiliate, Caltex Australia Limited.
 
In 2009, the company completed the sale of businesses in Brazil, Haiti, Nigeria, Benin, Cameroon, Republic of the Congo, Côte d’Ivoire, Togo, Kenya, Uganda, India, Italy, Peru and Chile. The company retained its lubricants business in Brazil. In addition, the company sold its interest in about 465 individual service-station sites in various other countries, including the United States. The majority of these sites continue to market company-branded gasoline through new supply agreements.
 
The company also manages other marketing businesses globally. Chevron markets aviation fuel at more than 875 airports. The company also markets an extensive line of lubricant and coolant products under brand names that include Havoline, Delo, Ursa, Meropa and Taro.
 
 
Pipelines: Chevron owns and operates an extensive network of crude-oil, refined-product, chemicals, natural-gas-liquids (NGL) and natural-gas pipelines and other infrastructure assets in the United States. The company also has direct or indirect interests in other U.S. and international pipelines. The company’s ownership interests in pipelines are summarized in the following table.
 
 
         
    Net Mileage1,2  
United States:
       
Crude Oil
    2,803  
Natural Gas
    2,255  
Petroleum Products3
    5,768  
         
Total United States
    10,826  
International:
       
Crude Oil
    700  
Natural Gas
    613  
Petroleum Products3
    438  
         
Total International
    1,751  
         
Worldwide
    12,577  
         
 
     
1
  Partially owned pipelines are included at the company’s equity percentage of total pipeline mileage.
2
  Excludes gathering lines related to the U.S. and international crude-oil and natural-gas production function.
3
  Includes the company’s share of chemical pipelines managed by the 50 percent-owned Chevron Phillips Chemical Company LLC.
 
During 2009, work progressed on a project that is designed to expand capacity by about 2 billion cubic feet at the Keystone natural-gas storage facility near Midland, Texas, which would bring the total capacity of the facility to nearly 7 billion cubic feet. The project completion is anticipated in the second quarter 2010.


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Work commenced in late 2009 to bring the Cal-Ky Pipeline, which was decommissioned in 2002, back into crude-oil service as a supply line for the Pascagoula Refinery. This crude-oil pipeline is also expected to provide additional outlets for the company’s equity production. The pipeline is expected to return to service in 2011. The company is also leading the evaluation and negotiations associated with a 136 mile, 24-inch pipeline from the proposed Jack and St. Malo production facility to Green Canyon 19 in the U.S. Gulf of Mexico. In December 2009, the company sold its interest in the western portion of the Texaco Expanded NGL Distribution System and its 64 percent ownership interest in Southcap Pipeline Company, which included Chevron’s 13.4 percent ownership interest in the Capline Pipeline.
 
Chevron has a 15 percent interest in the Caspian Pipeline Consortium (CPC) affiliate. CPC operates a crude-oil export pipeline from the Tengiz Field in Kazakhstan to the Russian Black Sea port of Novorossiysk. During 2009, CPC transported an average of approximately 743,000 barrels of crude oil per day, including 597,000 barrels per day from Kazakhstan and 146,000 barrels per day from Russia. In December 2009, partners approved the Expansion Project Implementation Plan, which is expected to increase the pipeline capacity to 1.4 million barrels per day. A final investment decision is expected in late 2010.
 
The company has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate that owns and operates a pipeline that primarily transports crude oil produced by Azerbaijan International Operating Company (AIOC) (owned 10.3 percent by Chevron) from Baku, Azerbaijan, through Georgia to deepwater port facilities in Ceyhan, Turkey. The BTC pipeline has a crude-oil capacity of 1.2 million barrels per day and transports the majority of the AIOC production. Another production export route for crude oil is the Western Route Export Pipeline, wholly owned by AIOC, with capacity to transport 145,000 barrels per day from Baku, Azerbaijan, to the marine terminal at Supsa, Georgia.
 
Chevron is the largest shareholder, with a 37 percent interest, in the West African Gas Pipeline Company Limited affiliate, which constructed, owns and operates the 421-mile (678-km) West African Gas Pipeline. The pipeline is designed to supply Nigerian natural gas to customers in Benin, Ghana and Togo for industrial applications and power generation. Compression facilities are expected to be installed in the second quarter 2010 that are designed to increase capacity to 170 million cubic feet per day.
 
Tankers: All tankers in Chevron’s controlled seagoing fleet were utilized during 2009. At any given time during 2009, the company had 42 deep-sea vessels chartered on a voyage basis, or for a period of less than one year. Additionally, the following table summarizes the capacity of the company’s controlled fleet.
 
 
                                 
    U.S. Flag     Foreign Flag  
          Cargo Capacity
          Cargo Capacity
 
    Number     (Millions of Barrels)     Number     (Millions of Barrels)  
 
Owned
    3       0.8       1       1.1  
Bareboat-Chartered
    2       0.7       18       27.1  
Time-Chartered2
                17       12.4  
                                 
Total
      5         1.5         36         40.6  
 
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.
 
Federal law requires that cargo transported between U.S. ports be carried in ships built and registered in the United States, owned and operated by U.S. entities, and manned by U.S. crews. The company’s U.S.-flagged fleet is engaged primarily in transporting refined products between the Gulf Coast and the East Coast and from California refineries to terminals on the West Coast and in Alaska and Hawaii. As part of its fleet modernization program, the company has two U.S.-flagged tankers scheduled for delivery in 2010 and plans to retire three U.S.-flagged product tankers between 2010 and 2011. The new tankers are expected to bring improved efficiencies to Chevron’s U.S.-flagged fleet.
 
The foreign-flagged vessels are engaged primarily in transporting crude oil from the Middle East, Asia, the Black Sea, Mexico and West Africa to ports in the United States, Europe, Australia and Asia. The company’s foreign-flagged vessels also transport refined products to and from various locations worldwide.


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In addition to the vessels described above, the company owns a one-sixth interest in each of seven liquefied-natural-gas (LNG) tankers transporting cargoes for the North West Shelf (NWS) Venture in Australia. The NWS project also has two LNG tankers under long-term time charter.
 
The Federal Oil Pollution Act of 1990 requires the phase-out by year-end 2010 of all single-hull tankers trading to U.S. ports or transferring cargo in waters within the U.S. Exclusive Economic Zone. As of the end of 2009, the company’s owned and chartered fleet was completely double-hulled. The company is a member of many oil-spill-response cooperatives in areas in which it operates around the world.
 
 
Chevron Phillips Chemical Company LLC (CPChem) is equally owned with ConocoPhillips Corporation. At the end of 2009, CPChem owned or had joint-venture interests in 34 manufacturing facilities and five research and technical centers in Belgium, Brazil, China, Colombia, Qatar, Saudi Arabia, Singapore, South Korea and the United States.
 
During 2009, CPChem completed construction of the 22 million-pounds-per-year Ryton® polyphenylene-sulfide (PPS) manufacturing facility at Borger, Texas. Ryton® PPS is an engineering thermoplastic used in a variety of applications, including automotives and electronics.
 
Outside the United States, CPChem’s 35 percent-owned Saudi Polymers Company continued construction during 2009 on a petrochemical project in Al Jubail, Saudi Arabia. The joint-venture project includes an olefins unit and downstream polyethylene, polypropylene, 1-hexene and polystyrene units. Project completion is expected in 2011.
 
CPChem continued construction during 2009 on the 49 percent-owned Q-Chem II project, located in both Mesaieed and Ras Laffan, Qatar. The project includes a 350,000-metric-ton-per-year high-density polyethylene plant and a 345,000-metric-ton-per-year normal alpha olefins plant, each utilizing CPChem proprietary technology. These plants are located adjacent to the existing Q-Chem I complex. The Q-Chem II project also includes a separate joint venture to develop a 1.3 million-metric-ton-per-year ethylene cracker in Ras Laffan, in which Q-Chem II owns 54 percent of the capacity rights. Start-up for the ethylene cracker is expected in March 2010, and start-up for the polyethylene and alpha olefins plants is anticipated in the third quarter 2010.
 
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 in most engine applications, such as passenger car, heavy-duty diesel, marine, locomotive and motorcycle engines, and additives for fuels to improve engine performance and extend engine life. During 2009, production began at the detergent expansion facility in Palau Sakra, Singapore. This additional capacity enhances the company’s ability to produce detergent components for applications in marine and automotive engines.
 
Other Businesses
 
 
Chevron’s U.S.-based mining company produces and markets coal and molybdenum. Sales occur in both U.S. and international markets.
 
The company owns and is the operator of a surface coal mine in Kemmerer, Wyoming, an underground coal mine, North River, in Alabama, and a surface coal mine in McKinley, New Mexico. The company continues to actively market for sale its coal reserves at the North River Mine and elsewhere in Alabama. The decision was made in late 2009 to suspend production at the McKinley Mine, and conduct reclamation activities in 2010. The company also owns a 50 percent interest in Youngs Creek Mining Company LLC, which was formed to develop a coal mine in northern Wyoming. Coal sales from wholly owned mines in 2009 were 10 million tons, down about 1 million tons from 2008.
 
At year-end 2009, Chevron controlled approximately 193 million tons of proven and probable coal reserves in the United States, including reserves of low-sulfur coal. The company is contractually committed to deliver between 7 million and 9 million tons of coal per year through the end of 2012 and believes it will satisfy these contracts from existing coal reserves.


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In addition to the coal operations, Chevron owns and operates the Questa molybdenum mine in New Mexico. At year-end 2009, Chevron controlled approximately 53 million pounds of proven molybdenum reserves at Questa. Underground development and production plans at Questa were scaled back in 2009 in response to weakening prices for molybdenum.
 
 
Chevron’s power generation business has interests in 13 power assets with a total operating capacity of more than 3,100 megawatts, primarily through joint ventures in the United States and Asia. Twelve of these are efficient combined-cycle and gas-fired cogeneration facilities that utilize waste heat recovery to produce electricity and support industrial thermal hosts. The thirteenth facility is a wind farm, located in Casper, Wyoming, that began operating in late 2009. The 100 percent-owned and operated Casper Wind Farm is a small-scale wind power facility designed to optimize the efficient use of a decommissioned refinery site for delivery of clean, renewable energy to the local utility provider.
 
The company has major geothermal operations in Indonesia and the Philippines and is investigating 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 18 and “Research and Technology” below.
 
 
Chevron Energy Solutions (CES) is a wholly owned subsidiary that designs and implements sustainable solutions for public institutions and businesses to increase energy efficiency and reliability, reduce energy costs, and utilize renewable and alternative-power technologies. Since 2000, CES has developed hundreds of projects that help governments, educational institutions and other customers reduce their energy costs and environmental impact. Major projects completed by CES in 2009 included solar and energy-efficiency installations for the Los Angeles County Metropolitan Transportation Authority and the San Jose Unified School District, which were the largest projects of their kind for a U.S. transit authority and school district.
 
 
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. 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 Technology Ventures (CTV) manages investments and projects in emerging energy technologies and their integration into Chevron’s core businesses. As of the end of 2009, CTV continued to explore technologies such as next-generation biofuels and advanced solar.
 
Chevron’s research and development expenses were $603 million, $702 million and $510 million for the years 2009, 2008 and 2007, 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. The company’s overall investment in this area is not significant to the company’s consolidated financial position.
 
 
Virtually all aspects of the company’s businesses are subject to various U.S. federal, state and local environmental, health and safety laws and regulations and to similar laws and regulations in other countries. These regulatory requirements continue to change and increase in both number and complexity and to govern not only the manner in which the company conducts its operations, but also the products it sells. Most of the costs of complying with the many laws and regulations pertaining to its operations are, or are expected to become, embedded in the normal costs of conducting business.
 
In 2009, the company’s U.S. capitalized environmental expenditures were approximately $887 million, representing approximately 15 percent of the company’s total consolidated U.S. capital and exploratory expenditures. These environmental expenditures include capital outlays to retrofit existing facilities as well as those associated with new


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facilities. The expenditures relate mostly to air- and water-quality projects and activities at the company’s refineries, oil and gas producing facilities, and marketing facilities. For 2010, the company estimates U.S. capital expenditures for environmental control facilities will be approximately $831 million. The future annual capital costs are uncertain and will be governed by several factors, including future changes to regulatory requirements.
 
Chevron expects an increase in environment-related regulations, including those that are intended to address concerns about greenhouse gas emissions and global climate change, in the countries where it has operations. For instance, under California’s Global Warming Solutions Act enacted in 2006, the California Air Resources Board (CARB), charged with implementing the law, has adopted a new low-carbon fuel standard intended to reduce the carbon intensity of transportation fuels, which is expected to apply beginning in 2011. Additionally, CARB is expected to propose regulations to implement the “cap and trade” emissions regulation provisions of the law, for adoption in the second half 2010. The effect of any such regulation on the company’s business is uncertain.
 
Refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages FS-16 through FS-17 for additional information on environmental matters and their impact on Chevron and on the company’s 2009 environmental expenditures, remediation provisions and year-end environmental reserves. Refer also to Item 1A. Risk Factors on pages 30 through 32 for a discussion of greenhouse gas regulation and climate change.
 
 
The company’s Internet Web site is at 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 at the SEC’s Web site at www.sec.gov.
 
Item 1A.   Risk Factors
 
Chevron is a major fully integrated petroleum company with a diversified business portfolio, a strong balance sheet, and a history of generating sufficient cash to fund capital and exploratory expenditures and to pay dividends. Nevertheless, some inherent risks could materially impact the company’s financial results of operations or financial condition.
 
 
Chevron is primarily in a commodities business with 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 and geopolitical risk.
 
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 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 schedule; and efficient and profitable operation of mature properties.
 
 
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, including hurricanes, floods and other forms of severe weather, war, civil unrest and other political events, fires, earthquakes, explosions and system failures, any of which could result in suspension of operations or harm to people or the natural environment.


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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 the company’s business. Chevron 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 arising from private litigation or government action, either as a result of an accidental, unlawful discharge or as a result of new conclusions on 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.
 
 
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 restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries. Internal unrest, acts of violence or strained relations between a government and the company or other governments may affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. At December 31, 2009, 26 percent of the company’s net proved reserves were located in Kazakhstan. The company also has significant interests in Organization of Petroleum Exporting Countries (OPEC)-member countries including Angola, Nigeria and Venezuela and in the Partitioned Zone between Saudi Arabia and Kuwait. Twenty-two percent of the company’s net proved reserves, including affiliates, were located in OPEC countries at December 31, 2009.
 
 
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. For instance, the Kyoto Protocol, Australia’s proposed legislation and California’s Global Warming Solutions Act, along with other actual or pending federal, state and provincial regulations, envision a reduction of greenhouse gas emissions through market-based regulatory programs, technology-based or performance-based standards or a combination of them. The company is subject to existing greenhouse gas emissions limits in jurisdictions where such regulation is currently effective, including the European Union and New Zealand.
 
In December 2009, the U.S. Environmental Protection Agency (EPA) issued a final endangerment finding for greenhouse gases, which specifically found that emissions of six greenhouse gases threaten the public health and welfare and that greenhouse gases from new motor vehicles and engines also contribute to such pollution. These findings do not themselves impose regulatory requirements. However, the agency is currently in the process of promulgating greenhouse gas emission standards for light-duty vehicles and regulations that would require certain stationary source facilities that exceed an as-yet undetermined threshold to obtain permits in advance, which permits could require implementation of so-called “best available control technologies.” In June 2009, the U.S. House of Representatives approved the American Clean Energy and Security Act. This is known as the Waxman-Markey bill, which includes provisions for a cap-and-trade program, aimed at controlling and reducing emissions of greenhouse gases in the United States. At this time it is not possible to predict whether or when the U.S. Senate may act on climate change legislation, how any bill approved by the Senate will be reconciled with the Waxman-Markey legislation or whether any federal legislation will supersede the EPA’s regulatory actions.
 
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 by jurisdiction depending on the laws enacted in each jurisdiction, the company’s activities in it and market conditions. The company’s exploration and production of crude oil, natural gas and


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various minerals such as coal; 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 result in greenhouse gas emissions that could well be regulated. 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 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.
 
 
In preparing the company’s periodic reports under the Securities Exchange Act of 1934, including its financial statements, Chevron’s management is required under 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.
 
Item 1B.     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-64 through FS-77. Note 13, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-45.
 
Item 3.     Legal Proceedings
 
Ecuador Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador, brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations, and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpet’s ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40 million. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations.
 
Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs


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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. With regard to the facts, the company believes that the evidence confirms that Texpet’s remediation was properly conducted and that the remaining environmental damage reflects Petroecuador’s failure to timely fulfill its legal obligations and Petroecuador’s further conduct since assuming full control over the operations.
 
In April 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $8 billion, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, health care systems, and additional infrastructure for Petroecuador. The engineer’s report also asserted that an additional $8.3 billion could be assessed against Chevron for unjust enrichment. The engineer’s report is not binding on the court. Chevron also believes that the engineer’s work was performed and his report prepared in a manner contrary to law and in violation of the court’s orders. Chevron submitted a rebuttal to the report in which it asked the court to strike the report in its entirety. In November 2008, the engineer revised the report and, without additional evidence, recommended an increase in the financial compensation for purported damages to a total of $18.9 billion and an increase in the assessment for purported unjust enrichment to a total of $8.4 billion. Chevron submitted a rebuttal to the revised report, which the court dismissed. In September 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 petitioned to be recused. In late September 2009, the judge was recused, and in October 2009, the full chamber of the provincial court affirmed the recusal, resulting in the appointment of a new judge. Chevron filed motions to annul all of the rulings made by the prior judge, but the new judge denied these motions. The court has completed most of the procedural aspects of the case and could render a judgment at any time. Chevron will continue a vigorous defense of any attempted imposition of liability.
 
In the event of an adverse judgment, Chevron would expect to pursue its appeals and vigorously defend against enforcement of any such judgment; therefore, the ultimate outcome — and 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 engineer’s report, management does not believe the report has any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to estimate a reasonably possible loss (or a range of loss).
 
Government Proceedings
In November 2008, the California Air Resources Board (CARB) proposed a civil penalty against the company’s Sacramento, California, terminal for alleged violations between August and December 2007 of CARB’s regulations governing the minimum concentration of additives in gasoline. Due to a computer programming error, the Sacramento terminal’s automatic dispensers had failed to inject additive detergent into a gasoline line.
 
In November 2008, CARB proposed a civil penalty against the company’s Richmond, California, refinery for a notice of violation relating to gasoline that was not properly certified as to composition. The company corrected the composition certificates for the gasoline without requiring any change to the composition of the gasoline. In July 2009, CARB issued the refinery a notice of violation relating to an error in gasoline blending that caused the product composition certifications to be in error. The composition certifications were corrected without requiring any change to the gasoline. Discussions with CARB officials relating to all of these matters took place in the fourth quarter 2009 and continue in 2010.
 
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 the company undertook to install and operate certain air pollution abatement equipment at its Hawaii Refinery pursuant to Clean Air Act settlement with the United States Environmental Protection Agency and DOH. The company has disputed many of the allegations.
 
Item 4.     Submission of Matters to a Vote of Security Holders
 
None.


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PART II
 
 
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-24.
 
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, 2009
    516       75.79              
Nov. 1 – Nov. 30, 2009
    2,380       78.59              
Dec. 1 – Dec. 31, 2009
                       
                                 
Total Oct. 1 – Dec. 31, 2009
    2,896       78.09              
                                 
 
(1) Pertains to common shares repurchased during the three-month period ended December 31, 2009, from company employees for required personal income tax withholdings on the exercise of the stock options issued to management and employees under the company’s broad-based employee stock options, long-term incentive plans and former Texaco Inc. stock option plans. Also includes shares delivered or attested to in satisfaction of the exercise price by holders of certain former Texaco Inc. employee stock options exercised during the three-month period ended December 31, 2009.
 
(2) In September 2007, the company authorized stock repurchases of up to $15 billion that may be made from time to time at prevailing prices as permitted by securities laws and other requirements and subject to market conditions and other factors. The program is authorized for a period of up to three years, expiring in September 2010, and may be discontinued at any time. As of December 31, 2009, 118,996,749 shares had been acquired under this program for $10.1 billion. No share repurchases occurred in 2009.
 
Item 6.     Selected Financial Data
 
The selected financial data for years 2005 through 2009 are presented on page FS-63.
 
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 10 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-39.
 
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.


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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 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 Chief Financial Officer concluded that the company’s disclosure controls and procedures were effective as of December 31, 2009.
 
(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 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, 2009.
 
The effectiveness of the company’s internal control over financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included on page FS-26.
 
(c)   Changes in Internal Control Over Financial Reporting
 
During the quarter ended December 31, 2009, 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.


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PART III
 
Item 10.     Directors, Executive Officers and Corporate Governance
 
Executive Officers of the Registrant at February 25, 2010
 
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
  53  
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
  59  
Vice Chairman of the Board and Executive
Vice President (since 2010)
  Worldwide Exploration and
Production Activities and Global
       
Executive Vice President (2005 through 2009)
  Gas Activities, including Natural
Gas Trading
J.E. Bethancourt
  58   Executive Vice President (since 2003)   Technology; Mining; Health,
Environment and Safety; Project
Resources Company; Procurement
C.A. James
  55   Executive Vice President (since 2009)
Vice President and General Counsel (2002 to 2009)
  Law; Human Resources
M.K. Wirth
  49   Executive Vice President (since 2006)
President of Global Supply and Trading (2004
  to 2006)
  Global Refining, Marketing, Lubricants, and Supply and
Trading, excluding Natural
Gas Trading; Chemicals
P.E. Yarrington
  53  
Vice President and Chief Financial Officer
(since 2009)
  Finance
       
Vice President and Treasurer (2007 through 2008)
Vice President, Policy, Government and Public
Affairs (2002 to 2007)
   
R.H. Pate
  47   Vice President and General Counsel (since 2009) Partner and Head of Global Competition Practice
  of Hunton & Williams LLP (2005 to 2009)
  Law
 
The information about directors required by Item 401(a) and (e) of Regulation S-K and contained under the heading “Election of Directors” in the Notice of the 2010 Annual Meeting and 2010 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 2010 Annual Meeting of Stockholders (the “2010 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 2010 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 2010 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 2010 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.


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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 2010 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 2010 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 2010 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 2010 Proxy Statement shall not be deemed “filed” for purposes 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 2010 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 2010 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 2010 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 2010 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 Independent Registered Public Accounting Firm” in the 2010 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.


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Table of Contents

 
 
Item 15.     Exhibits, Financial Statement Schedules
 
(a) The following documents are filed as part of this report:
 
              (1)  Financial Statements:
 
     
    Page(s)
 
  FS-26
  FS-27
  FS-28
  FS-29
  FS-30
  FS-31
  FS-32 to FS-61
 
              (2)  Financial Statement Schedules:
 
Schedule Of Valuation And Qualifying Accounts Disclosure

 
                         
    Year Ended December 31  
    2009     2008     2007  
 
Employee Termination Benefits:
                       
Balance at January 1
  $ 44     $ 117     $ 28  
(Deductions from) additions to expense
    (12 )     (13 )     106  
Payments
    (19 )     (60 )     (17 )
                         
Balance at December 31
  $ 13     $ 44     $ 117  
                         
Allowance for Doubtful Accounts:
                       
Balance at January 1
  $ 275     $ 200     $ 217  
Additions to expense
    92       105       29  
Bad debt write-offs
    (74 )     (30 )     (46 )
                         
Balance at December 31
  $ 293     $ 275     $ 200  
                         
Deferred Income Tax Valuation Allowance:*
                       
Balance at January 1
  $ 7,535     $ 5,949     $ 4,391  
Additions to deferred income tax expense
    2,204       2,599       1,894  
Reduction of deferred income tax expense
    (1,818 )     (1,013 )     (336 )
                         
Balance at December 31
  $ 7,921     $ 7,535     $ 5,949  
                         
 
See also Note 15 to the Consolidated Financial Statements beginning on page FS-46.
 
              (3)  Exhibits:
 
         The Exhibit Index on pages E-1 and E-2 lists the exhibits that are filed as part of this report.


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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 25th day of February, 2010.
 
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 25th day of February, 2010.
 
     
Principal Executive Officers
   
(and Directors)   Directors
 
/s/John S. Watson
John S. Watson, Chairman of the
Board and Chief Executive Officer
  Samuel H. Armacost*
Samuel H. Armacost
     
/s/George L. Kirkland
George L. Kirkland, Vice Chairman of the Board
  Linnet F. Deily*
Linnet F. Deily
     
    Robert E. Denham*
Robert E. Denham
     
    Robert J. Eaton*
Robert J. Eaton
     
Principal Financial Officer

/s/Patricia E. Yarrington
Patricia E. Yarrington, Vice President and
Chief Financial Officer

Principal Accounting Officer

/s/Mark A. Humphrey
Mark A. Humphrey, Vice President and Comptroller
 
Enrique Hernandez, Jr.*
Enrique Hernandez, Jr.

Franklyn G. Jenifer*
Franklyn G. Jenifer

Sam Nunn*
Sam Nunn
     
    Donald B. Rice*
Donald B. Rice
     
    Kevin W. Sharer*
Kevin W. Sharer
     
*By: /s/Lydia I. Beebe
Lydia I. Beebe,
Attorney-in-Fact
  Charles R. Shoemate*
Charles R. Shoemate
     
    Ronald D. Sugar*
Ronald D. Sugar
     
    Carl Ware*
Carl Ware


39


 

Financial Table of Contents
 

FS-2
         
       
       
       
       
       
       
       
       
       
       
       
       
       
       
       
       
       
       
 
FS-25
FS-32
             
Notes to the Consolidated Financial Statements        
Note 1          
Note 2          
Note 3          
Note 4          
Note 5          
Note 6          
Note 7          
Note 8          
Note 9          
Note 10          
Note 11          
Note 12          
Note 13          
Note 14          
Note 15          
Note 16          
Note 17          
Note 18          
Note 19          
Note 20          
Note 21          
Note 22          
Note 23          
Note 24          
Note 25          
Note 26          
   
 
       
Five-Year Financial Summary FS-63        
Supplemental Information on Oil and Gas Producing Activities FS-64        







FS-1



Table of Contents

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

 
 
 

Key Financial Results
                           
Millions of dollars, except per-share amounts   2009       2008     2007  
       
Net Income Attributable to
Chevron Corporation
  10,483       23,931     18,688  
Per Share Amounts:
                         
Net Income Attributable to
Chevron Corporation
                         
– Basic
  $ 5.26       $ 11.74     $ 8.83  
– Diluted
  $ 5.24       $ 11.67     $ 8.77  
Dividends
  $ 2.66       $ 2.53     $ 2.26  
Sales and Other
Operating Revenues
  $ 167,402       $ 264,958     $ 214,091  
Return on:
                         
Capital Employed
    10.6 %       26.6 %     23.1 %
Stockholders’ Equity
    11.7 %       29.2 %     25.6 %
       
Earnings by Major Operating Area
                           
Millions of dollars   2009       2008     2007  
       
Upstream – Exploration and Production
                       
United States
  2,216       7,126     4,532  
International
    8,215         14,584       10,284  
       
Total Upstream
    10,431         21,710       14,816  
       
Downstream – Refining, Marketing
and Transportation
                         
United States
    (273 )       1,369       966  
International
    838         2,060       2,536  
       
Total Downstream
    565         3,429       3,502  
       
Chemicals
    409         182       396  
All Other
    (922 )       (1,390 )     (26 )
       
Net Income Attributable to
Chevron Corporation(1),(2)
  $ 10,483       $ 23,931     $ 18,688  
       
       
(1) Includes foreign currency effects:
    $   (744 )       $    862       $   (352 )
(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, 2009.
Business Environment and Outlook
     Chevron is a global energy company with significant 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 largely on the profitability of its upstream (exploration and production) and downstream (refining, marketing and transportation) business segments. The single biggest factor that affects the results of operations for both segments is movement in the
price of crude oil. In the downstream business, crude oil is the largest cost component of refined products. The overall trend in earnings is typically less affected by results from the company’s chemicals business and other activities and investments. Earnings for the company in any period may also be influenced by events or transactions that are infrequent or unusual in nature.
     The company’s operations, especially upstream, can also be affected by changing economic, regulatory and political environments in the various countries in which it operates, including the United States. Civil unrest, acts of violence or strained relations between a government and the company or other governments may impact the company’s operations or investments. Those developments have at times significantly affected the company’s operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries.
     To sustain its long-term competitive position in the upstream business, the company must develop and replenish an inventory of projects that offer attractive financial returns for the investment required. Identifying promising areas for exploration, acquiring the necessary rights to explore for and to produce crude oil and natural gas, drilling successfully, and handling the many technical and operational details in a safe and cost-effective manner are all important factors in this effort. Projects often require long lead times and large capital commitments. From time to time, certain governments have sought to renegotiate contracts or impose additional costs on the company. Governments may attempt to do so in the future. The company will continue to monitor these developments, take them into account in evaluating future investment opportunities, and otherwise seek to mitigate any risks to the company’s current operations or future prospects.
     The company also continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value or to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and growth. Refer to the “Results of Operations” section beginning on FS-6 for discussions of net gains on asset sales during 2009. Asset dispositions and restructurings may also occur in future periods and could result in significant gains or losses.
     In recent years, Chevron and the oil and gas industry at large experienced an increase in certain costs that exceeded the general trend of inflation in many areas of the world. This increase in costs affected the company’s operating expenses and capital programs for all business segments, but particularly for upstream. Softening of these cost pressures started in late 2008 and continued through most of 2009. Costs began to level out in the fourth quarter 2009. The company continues to actively manage its schedule of work,


FS-2


Table of Contents

contracting, procurement and supply-chain activities to effectively manage costs. (Refer to the “Upstream” section below for a discussion of the trend in crude-oil prices.)
     The company continues to closely monitor developments in the financial and credit markets, the level of worldwide economic activity and the implications to the company of movements in prices for crude oil and natural gas. Management is taking these developments into account in the conduct of daily operations and for business planning. The company remains confident of its underlying financial strength to address potential challenges presented in this environment. (Refer also to the “Liquidity and Capital Resources” section beginning on FS-11.)
(GRAPH)
     Comments related to earnings trends for the company’s major business areas are as follows:
     Upstream Earnings for the upstream segment are closely aligned with industry price levels for crude oil and natural gas. Crude-oil and natural-gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Moreover, any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments, and attempts to manage risks in operating its facilities and businesses. Besides the impact of the fluctuation in prices for crude oil and natural gas, the longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts and changes in tax laws and regulations.
     Price levels for capital and exploratory costs and operating expenses associated with the production of crude oil and
natural gas can also be subject to external factors beyond the company’s control. External factors include not only the general level of inflation but also commodity prices and prices charged by the industry’s material and service providers, which can be affected by the volatility of the industry’s own supply-and-demand conditions for such materials and services. Capital and exploratory expenditures and operating expenses also can be affected by damage to production facilities caused by severe weather or civil unrest.
     The chart at left shows the trend in benchmark prices for West Texas Intermediate (WTI) crude oil and U.S. Henry Hub natural gas. Industry price levels for crude oil continued to be volatile during 2009, with prices for WTI ranging from $34 to $81 per barrel. The WTI price averaged $62 per barrel for the full-year 2009, compared to $100 in 2008. The decline in prices from 2008 was largely associated with a weakening in global economic conditions and a reduction in the demand for crude oil and petroleum products. As of mid-February 2010, the WTI price was about $77.
     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 that is a function of the number of refineries that are able to process this lower-quality feedstock into light products
(motor gasoline, jet fuel, aviation gasoline and diesel fuel). The differential remained narrow through 2009 as production declines in the industry have been mainly for lower-quality crudes.
     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
()


FS-3


Table of Contents

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

 
 
 

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 about $3.80 per thousand cubic feet (MCF) during 2009, compared with almost $9 during 2008. At December 31, 2009, and as of
mid-February 2010, the Henry Hub spot price was about $5.70 and $5.50 per MCF, respectively. Fluctuations in the price for natural gas in the United States are closely associated with customer demand relative to the volumes produced in North America and the level of inventory in underground storage. Weaker U.S. demand in 2009 was associated with the economic slowdown.
     Certain international natural-gas markets in which the company operates have different supply, demand and regulatory circumstances, which historically have resulted in lower average sales prices for the company’s production of natural gas in these locations. Chevron continues to invest in long-term projects in these locations to install infrastructure to produce and liquefy natural gas for transport by tanker to other markets where greater demand results in higher prices. International natural-gas realizations averaged about $4.00 per MCF during 2009, compared with about $5.20 per MCF during 2008. Unlike prior years, these realizations compared favorably with those in the United States during 2009, primarily as a result of the deterioration of U.S. supply-and-demand conditions resulting from the economic slowdown. (See page FS-10 for the company’s average natural gas realizations for the U.S. and international regions.)
     The company’s worldwide net oil-equivalent production in 2009 averaged 2.70 million barrels per day. About one-fifth of the company’s net oil-equivalent production in 2009 occurred in the OPEC-member countries of Angola, Nigeria and Venezuela and in the Partitioned Zone between Saudi Arabia and Kuwait. For the year 2009, the company’s net oil production was reduced by an average of 20,000 barrels per day due to quotas imposed by OPEC. All of the imposed curtailments took place during the first half of the year. At the December 2009 meeting, members of OPEC supported maintaining production quotas in effect since December 2008.
     The company estimates that oil-equivalent production in 2010 will average approximately 2.73 million barrels per day. This estimate is subject to many factors and uncertainties, including additional quotas that may be imposed by OPEC, price effects on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on the scope of company operations, delays in project startups, fluctuations in demand for natural gas in various markets, weather conditions that may shut in production, civil unrest, changing
geopolitics, 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-69 for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2007 and each year-end from 2007 through 2009, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2009.
     Downstream Earnings for the downstream segment are closely tied to margins on the refining and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil and feedstocks for chemical manufacturing. Industry margins are sometimes volatile and can be affected by the global and regional
supply-and-demand balance for refined products and by changes in the price of crude oil used for refinery feedstock. Industry margins can also be influenced by refined-product inventory levels, geopolitical events, cost of materials and services, refinery maintenance programs and disruptions at refineries 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 and marketing network and the effectiveness of the crude-oil and product-supply functions. Profitability can also be affected by the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude-oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refinery and distribution network.
     The company’s most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Latin America, Asia, southern Africa and the United Kingdom. Chevron operates or has significant ownership interests in refineries in each of these areas except Latin America. The company completed sales of marketing businesses during 2009 in certain countries in Latin America and Africa. The company plans to discontinue, by mid-2010, sales of Chevron- and Texaco-branded motor fuels in the mid-Atlantic and other eastern states, where the company sold to retail customers through approximately 1,100 stations and to commercial and industrial customers through supply arrangements. Sales in these markets


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represent approximately 8 percent of the company’s total U.S. retail fuel sales volumes. Additionally, in January 2010, the company sold the rights to the Gulf trademark in the United States and its territories that it had previously licensed for use in the U.S. Northeast and Puerto Rico.
     The company’s refining and marketing margins in 2009 were generally weak due to challenging industry conditions, including a sharp drop in global demand reflecting the economic slowdown, excess refined-product supplies and surplus refining capacity. Given these conditions, in January 2010 the company announced to its employees that high-level evaluations of Chevron’s refining and marketing organizations had been completed. These evaluations concluded that the company’s downstream organization should be restructured to improve operating efficiency and achieve sustained improvement in financial performance. Details of the restructuring will be further developed over the next three to six months and may include exits from additional markets, dispositions of assets, reductions in the number of employees and other actions, which may result in gains or losses in future periods.
     Refer to the “Results of Operations” section on pages FS-7 and FS-8 for additional discussion of the company’s downstream operations.
     Chemicals Earnings in the petrochemicals business are closely tied to global chemical demand, industry inventory levels and plant capacity utilization. Feedstock and fuel costs, which tend to follow crude-oil and natural-gas price movements, also influence earnings in this segment.
     Refer to the “Results of Operations” section on page FS-8 for additional discussion of chemical earnings.
Operating Developments
Key operating developments and other events during 2009 and early 2010 included the following:
Upstream
Angola Production began at the 39.2 percent-owned and operated Mafumeira Norte offshore project in Block 0 and the 31 percent-owned and operated deepwater Tombua-Landana project in Block 14. Mafumeira Norte is expected to reach maximum total daily production of 42,000 barrels of crude oil in the third quarter 2010, and the Tombua-Landana project is expected to reach its maximum total production of approximately 100,000 barrels of crude oil per day in 2011. The company also discovered crude oil offshore in the 39.2 percent-owned and operated Block 0 concession, extending a trend of earlier discoveries in the Greater Vanza/Longui Area.
     Australia The company and its partners reached final investment decision to proceed with the development of the Gorgon Project, located offshore Western Australia, in which Chevron has a 47.3 percent-owned and operated interest as of December 31, 2009. In addition, the company finalized long-term sales agreements for delivery of liquefied natural gas (LNG) from the Gorgon Project with four Asian customers, three of which also acquired an ownership interest in the project. Nonbinding Heads of Agreement (HOAs) with three additional Asian customers were also signed in late 2009 and
early 2010 for delivery of LNG from the project. Negotiations continue to finalize binding sales agreements, which would bring LNG delivery commitments to a combined total of about 90 percent of Chevron’s share of LNG from the project.
     The company awarded front-end engineering and design contracts for the first phase of the Wheatstone natural gas project, also located offshore northwest Australia. The 75 percent-owned and
()
     operated facilities will have LNG processing capacity of 8.6 million metric tons per year and a
co-located domestic natural-gas plant. The facilities will support development of Chevron’s interests in the Wheatstone Field and nearby Iago Field. Agreements were signed with two companies to join the Wheatstone Project as combined 25 percent owners and suppliers of natural gas for the project’s first two LNG trains. In addition, nonbinding HOAs were signed with two Asian customers to take delivery of 4.9 million metric tons per year of LNG from the project (about 60 percent of the total LNG available from the foundation project) and to acquire a 16.8 percent equity interest in the Wheatstone Field licenses and a 12.6 percent interest in the foundation natural gas processing facilities at the final investment decision.
     In May 2009 the company announced the successful
completion of a well at the Clio prospect to further explore and appraise the 66.7 percent-owned Block WA-205-P. In 2009 and early 2010, the company also announced natural-gas discoveries at the Kentish Knock prospect in the 50 percent-owned Block WA-365-P, the Achilles and Satyr prospects in the 50 percent-owned Block WA-374-P and the Yellowglen prospect in the 50 percent-owned WA-268-P Block. All prospects are Chevron-operated. Proved reserves have not been recognized for these discoveries.
     Brazil Production started at the 51.7 percent-owned and operated deepwater Frade Field, which is projected to attain maximum total production of 72,000 oil-equivalent barrels per day in 2011. Also, in early 2010 a final investment decision was reached to develop the 37.5 percent-owned, partner-operated Papa-Terra Field, where first production is expected in 2013. Project facilities are designed with a capacity to handle up to 140,000 barrels of crude oil per day.
     Republic of the Congo Crude oil was discovered in the northern portion of the 31.5 percent-owned, partner-operated Moho-Bilondo deepwater permit area. This discovery follows two others made in 2007 in the same permit area.


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

 
 
 

     Venezuela In February 2010, a Chevron-led consortium was named the operator of a heavy-oil project composed of three blocks in the Orinoco Oil Belt of eastern Venezuela.
     United States First oil was achieved at the 58 percent-owned and operated Tahiti Field in the deepwater Gulf of Mexico, reaching maximum total production of 135,000 barrels of oil-equivalent per day. The company also discovered crude oil at the Chevron-operated and 55 percent-owned Buckskin prospect in the deepwater Gulf of Mexico. The first appraisal well is scheduled to begin drilling in the second quarter 2010.
Downstream
The company sold businesses during 2009 in Brazil, Haiti, Nigeria, Benin, Cameroon, Republic of the Congo, Côte d’Ivoire, Togo, Kenya, Uganda, India, Italy, Peru and Chile.
Other
Common Stock Dividends The quarterly common stock dividend increased by 4.6 percent in July 2009, to $0.68 per share. 2009 was the 22nd consecutive year that the company increased its annual dividend payment.
     Common Stock Repurchase Program The company did not acquire any shares during 2009 under its $15 billion repurchase program, which began in 2007 and expires in September 2010. As of December 31, 2009, 119 million common shares had been acquired under this program for $10.1 billion.
Results of Operations
Major Operating Areas The following section presents the results of operations for the company’s business segments – upstream, downstream and chemicals – as well as for “all other,” which includes mining, power generation businesses, the various companies and departments that are managed at the corporate level, and the company’s investment in Dynegy prior to its sale in May 2007. Earnings are also presented for the U.S. and international geographic areas of the upstream and downstream business segments. (Refer to Note 11, beginning on page FS-40, 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 – Exploration and Production
                           
Millions of dollars   2009       2008     2007  
       
Earnings
  $   2,216       $   7,126     $   4,532  
       
     U.S upstream earnings of $2.2 billion in 2009 decreased $4.9 billion from 2008. Lower prices for crude oil and natural gas reduced earnings by about $5.2 billion between periods, and gains on asset sales declined by approximately $900 million. Partially offsetting these effects was a benefit of about $1.3 billion resulting from an increase in net oil-equivalent production. An approximate $600 million benefit to income from lower operating expenses was more than offset by higher depreciation expense. The benefit from
()
lower operating expenses was largely associated with absence of charges for damages related to the 2008 hurricanes in the Gulf of Mexico.
     U.S upstream earnings of $7.1 billion in 2008 increased $2.6 billion from 2007. Higher average prices for crude oil and natural gas increased earnings by $3.1 billion between periods. Also contributing to the higher earnings were gains of approximately $1 billion on asset sales, including a $600 million gain on an
asset-exchange transaction. Partially offsetting these benefits were adverse effects of about $1.6 billion associated with lower oil-equivalent production and higher operating expenses, which included approximately $400 million of expenses resulting from damage to facilities in the Gulf of Mexico caused by hurricanes.
     The company’s average realization for crude oil and natural gas liquids in 2009 was $54.36 per barrel, compared with $88.43 in 2008 and $63.16 in 2007. The average natural-gas realization was $3.73 per thousand cubic feet in 2009, compared with $7.90 and $6.12 in 2008 and 2007, respectively.


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     Net oil-equivalent production in 2009 averaged 717,000 barrels per day, up 6.9 percent from 2008 and down 3.5 percent from 2007. The increase between 2008 and 2009 was mainly due to the start-up of the Blind Faith Field in late 2008 and the Tahiti Field in the second quarter 2009. The decrease between 2007 and 2008 was mainly due to normal field declines and the adverse impact of the hurricanes. The net liquids component of oil-equivalent production for 2009 averaged 484,000 barrels per day, up approximately 15 percent from 2008 and 5 percent compared with 2007. Net natural-gas production averaged 1.4 billion cubic feet per day in 2009, down approximately 7 percent from 2008 and about 18 percent from 2007.
     Refer to the “Selected Operating Data” table on page FS-10 for the three-year comparative production volumes in the United States.
International Upstream – Exploration and Production
                           
Millions of dollars   2009       2008     2007  
       
Earnings*
  $   8,215       $   14,584     $   10,284  
       
       
*Includes foreign currency effects:
  $  (571 )       $   873       $  (417
     International upstream earnings of $8.2 billion in 2009 decreased $6.4 billion from 2008. Lower prices for crude oil and natural gas reduced earnings by $7.0 billion, while foreign-currency effects and higher operating and depreciation expenses decreased income by a total of $2.2 billion. Partially offsetting these items were benefits of $2.3 billion resulting from an increase in sales volumes of crude oil and about $500 million associated with asset sales and tax items related to the Gorgon Project in Australia.
     Earnings of $14.6 billion in 2008 increased $4.3 billion from 2007. Higher prices for crude oil and natural gas increased earnings by $4.9 billion. Partially offsetting the benefit of higher prices was an impact of about $1.8 billion associated with a reduction of
crude-oil sales volumes due to timing of certain cargo liftings and higher depreciation and operating expenses. Foreign-currency effects benefited earnings by $873 million in 2008, compared with a reduction to earnings of $417 million in 2007.
     The company’s average realization for crude oil and natural gas liquids in 2009 was $55.97 per barrel, compared with $86.51 in 2008 and $65.01 in 2007. The average natural-gas realization was $4.01 per thousand cubic feet in 2009, compared with $5.19 and $3.90 in 2008 and 2007, respectively.
     Net oil-equivalent production of 1.99 million barrels per day in 2009 increased about 7 percent and 6 percent from 2008 and 2007, respectively. The volumes for each year included production from oil sands in Canada. Absent the impact of prices on certain production-sharing and variable-royalty agreements, net
oil-equivalent production increased 4 percent in 2009 and 3 percent in 2008, when compared with prior years’ production.
     The net liquids component of oil-equivalent production was 1.4 million barrels per day in 2009, an increase of approximately 11 percent from 2008 and 5 percent from
2007. Net natural-gas production of 3.6 billion cubic feet per day in 2009 was down 1 percent and up 8 percent from 2008 and 2007, respectively.
     Refer to the “Selected Operating Data” table, on page FS-10, for the three-year comparative of international production volumes.
U.S. Downstream – Refining, Marketing and Transportation
                           
Millions of dollars   2009       2008     2007  
       
Earnings
  $   (273 )     $   1,369     $   966  
       
     U.S downstream operations lost $273 million in 2009, an earnings decrease of approximately $1.6 billion from 2008. A decline in refined product margins resulted in a negative earnings variance of $1.7 billion. Partially offsetting were lower operating expenses, which benefited earnings by $300 million. Earnings of $1.4 billion in 2008 increased about $400 million from 2007 due mainly to improved
(GRAPH)
margins on the sale of refined products and gains on derivative commodity instruments. Operating expenses were higher between 2007 and 2008.
     Sales volumes of refined products were 1.40 million barrels per day in 2009, a decrease of 1 percent from 2008. The decline was associated with reduced demand for jet fuel and fuel oil, principally associated with the downturn in the U.S. economy. Sales volumes of refined products were 1.41 million barrels per day in 2008, a decrease of 3 percent from 2007. Branded gasoline sales volumes of 617,000 barrels per day in 2009 were up about 3 percent and down 2 percent from 2008 and 2007, respectively.
     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.


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

 
 
 

International Downstream – Refining, Marketing and Transportation
                           
Millions of dollars   2009       2008     2007  
       
Earnings*
  $   838       $   2,060     $   2,536  
       
*Includes foreign currency effects:
    $  (213 )       $   193       $   62  
     International downstream earnings of $838 million in 2009 decreased about $1.2 billion from 2008. An approximate $2.6 billion decline between periods was associated with weaker margins on the sale of gasoline and other refined products and the absence
()
     of gains recorded in 2008 on commodity derivative instruments. Foreign-currency effects produced a negative variance of $400 million. Partially offsetting these items was a $1.0 billion benefit from lower operating expenses associated mainly with contract labor, professional services and transportation costs and about a $550 million increase in gains on asset sales primarily in certain countries in Latin America and Africa. Earnings in 2008 of $2.1 billion decreased nearly $500 million from 2007. Earnings in 2007 included gains of approximately $1 billion on the sale of assets, which included marketing assets in the Benelux region of Europe and an interest in a refinery. The $500 million other improvement between years was associated primarily with a benefit from gains on derivative commodity instruments that was only partially offset by the impact of lower margins from sales of
refined products. Foreign-currency effects increased earnings by $193 million in 2008, compared with $62 million in 2007.
     Refined-product sales volumes were 1.85 million barrels per day in 2009, about 8 percent lower than in 2008 due mainly to the effects of asset sales and lower demand. Refined-product sales volumes were 2.02 million barrels per day in 2008, about level with 2007.
     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.
Chemicals
                           
Millions of dollars   2009       2008     2007  
       
Earnings*
  $   409       $   182     $   396  
       
*Includes foreign currency effects:
    $  15         $  (18 )     $  (3 )
     The chemicals segment includes the company’s Oronite subsidiary and the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem). In 2009, earnings were $409 million, compared with $182 million and $396 million in 2008
and 2007, respectively. For CPChem, the earnings improvement from 2008 to 2009 reflected lower utility and manufacturing costs as well as the absence of an impairment recorded in 2008. These benefits were partially offset by lower margins on the sale of commodity chemicals. For Oronite, earnings increased in 2009 due to higher margins on sales of lubricant and fuel additives, the effect of which more than offset the impact of lower sales volumes. In 2008, segment earnings were $182 million, compared with $396 million in 2007. Earnings declined in 2008 due to lower sales volumes of commodity chemicals by CPChem. Higher expenses for planned maintenance activities also contributed to the earnings decline. Earnings also declined for Oronite due to lower volumes and higher operating expenses.     
(GRAPH)
All Other
                           
Millions of dollars   2009       2008     2007  
       
Net Charges*
  $   (922 )     $   (1,390 )   $   (26 )
       
*Includes foreign currency effects:
    $  25         $  (186 )     $   6  
     All Other includes mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, alternative fuels and technology companies, and the company’s interest in Dynegy, Inc. prior to its sale in May 2007.
     Net charges in 2009 decreased $468 million from 2008 due to lower provisions for environmental remediation at sites


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Table of Contents

that previously had been closed or sold, favorable foreign-currency effects and lower expenses for employee compensation and benefits. Net charges in 2008 increased $1.4 billion from 2007. Results in 2008 included net unfavorable corporate tax items and increased costs of environmental remediation. Foreign-currency effects also contributed to the increase in net charges from 2007 to 2008. Results in 2007 included a $680 million gain on the sale of the company’s investment in Dynegy common stock and a loss of approximately $175 million associated with the early redemption of Texaco Capital Inc. bonds.
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below:
                           
Millions of dollars   2009       2008     2007  
       
Sales and other operating revenues
  167,402       264,958     214,091  
       
     Sales and other operating revenues decreased in 2009, due mainly to lower prices for crude oil, natural gas and refined products. Higher 2008 prices resulted in increased revenues compared with 2007.
                           
Millions of dollars   2009       2008     2007  
       
Income from equity affiliates
  3,316       5,366     4,144  
       
     Income from equity affiliates decreased in 2009 from 2008. Upstream-related affiliate income declined about $1.3 billion mainly due to lower earnings for Tengizchevroil (TCO) in Kazakhstan as a result of lower prices for crude oil. Downstream-related affiliate earnings were lower by approximately $1.0 billion primarily due to weaker margins and an unfavorable swing in foreign-currency effects. Income from equity affiliates increased in 2008 from 2007 largely due to improved upstream-related earnings at TCO as a result of higher prices for crude oil. Refer to Note 12, beginning on page FS-43, for a discussion of Chevron’s investments in affiliated companies.
                           
Millions of dollars   2009       2008     2007  
       
Other income
  918       2,681     2,669  
       
     Other income of $918 million in 2009 included gains of approximately $1.3 billion on asset sales. Other income of $2.7 billion in 2008 and 2007 included net gains from asset sales of $1.3 billion and $1.7 billion, respectively. Interest income was approximately $95 million in 2009, $340 million in 2008 and $600 million in 2007. Foreign-currency effects reduced other income by $466 million in 2009 while increasing other income by $355 million in 2008 and reducing other income by $352 million in 2007. In addition, other income in 2008 included approximately $700 million in favorable settlements and other items.
                           
Millions of dollars   2009       2008     2007  
       
Purchased crude oil and products
  99,653       171,397     133,309  
       
     Crude oil and product purchases in 2009 decreased $71.7 billion from 2008 due to lower prices for crude oil, natural gas and refined products. Crude oil and product purchases in 2008 increased $38.1 billion from 2007 due to higher prices for crude oil, natural gas and refined products.
                           
Millions of dollars   2009       2008     2007  
       
Operating, selling, general and administrative expenses
  22,384       26,551     22,858  
       
     Operating, selling, general and administrative expenses in 2009 decreased approximately $4.2 billion from 2008 primarily due to $1.4 billion of lower fuel and transportation expenses; $800 million of decreased costs for contract labor and professional services; absence of uninsured 2008 hurricane-related charges of $700 million; a decrease of about $500 million for environmental remediation activities; $200 million of lower costs for materials; and $600 million for other items. Total expenses for 2008 were about $3.7 billion higher than 2007 primarily due to $1.2 billion of higher costs for employee and contract labor and professional services; $600 million of increased transportation expenses; $700 million of uninsured losses associated with hurricanes in the Gulf of Mexico in 2008; an increase of about $300 million for environmental remediation activities; $200 million from higher material expenses; and $700 million from increases for other items.
                           
Millions of dollars   2009       2008     2007  
       
Exploration expense
  1,342       1,169     1,323  
       
     Exploration expenses in 2009 increased from 2008 due mainly to higher amounts for well write-offs in the United States and international operations. Expenses in 2008 declined from 2007 mainly due to lower amounts for well write-offs for operations in the United States.
                           
Millions of dollars   2009       2008     2007  
       
Depreciation, depletion and amortization
  12,110       9,528     8,708  
       
     Depreciation, depletion and amortization expenses increased in 2009 from 2008 due to incremental production related to start-ups for upstream projects in the United States and Africa and higher depreciation rates for certain other oil and gas producing fields. The increase in 2008 from 2007 was largely due to higher depreciation rates for certain crude-oil and natural-gas producing fields, reflecting completion of higher-cost development projects and asset-retirement obligations.
                           
Millions of dollars   2009       2008     2007  
       
Taxes other than on income
  17,591       21,303     22,266  
       
     Taxes other than on income decreased in 2009 from 2008 mainly due to lower import duties for the company’s downstream operations in the United Kingdom. Taxes other than on income decreased in 2008 from 2007 mainly due to lower import duties as a result of the effects of the 2007 sales


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Table of Contents

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

 
 
 

of the company’s Benelux refining and marketing businesses and a decline in import volumes in the United Kingdom.
                           
Millions of dollars   2009       2008     2007  
       
Interest and debt expense
  $    28           166  
       
     Interest and debt expense increased in 2009 due to an increase in long-term debt. Interest and debt expense decreased in 2008 because all interest-related amounts were being capitalized.
                           
Millions of dollars   2009       2008     2007  
       
Income tax expense
  7,965       19,026     13,479  
       
     Effective income tax rates were 43 percent in 2009, 44 percent in 2008 and 42 percent in 2007. The rate was lower in 2009 than in 2008 mainly due the effect in 2009 of deferred tax benefits and relatively low tax rates on asset sales, both related to an international upstream project. In addition, a greater proportion of before-tax income was earned in 2009 by equity affiliates than in 2008. (Equity-affiliate income is reported as a single amount on an
after-tax basis on the Consolidated Statement of Income.) Partially offsetting these items was the effect of a greater proportion of income earned in 2009 in tax jurisdictions with higher tax rates. The rate was higher in 2008 compared with 2007 primarily due to a greater proportion of income earned in tax jurisdictions with higher income tax rates. In addition, the 2007 period included a relatively low effective tax rate on the sale of the company’s investment in Dynegy common stock and the sale of downstream assets in Europe. Refer also to the discussion of income taxes in Note 15 beginning on page FS-46.
Selected Operating Data1,2
                           
    2009       2008     2007  
       
U.S. Upstream
                         
Net Crude Oil and Natural Gas
                         
Liquids Production (MBPD)
    484         421       460  
Net Natural Gas Production (MMCFPD)3
    1,399         1,501       1,699  
Net Oil-Equivalent Production (MBOEPD)
    717         671       743  
Sales of Natural Gas (MMCFPD)
    5,901         7,226       7,624  
Sales of Natural Gas Liquids (MBPD)
    17         15       25  
Revenues From Net Production
                         
Liquids ($/Bbl)
  $ 54.36       $ 88.43     $ 63.16  
Natural Gas ($/MCF)
  $ 3.73       $ 7.90     $ 6.12  
 
                         
International Upstream
                         
Net Crude Oil and Natural Gas
                         
Liquids Production (MBPD)
    1,362         1,228       1,296  
Net Natural Gas Production (MMCFPD)3
    3,590         3,624       3,320  
Net Oil-Equivalent
                         
Production (MBOEPD)4
    1,987         1,859       1,876  
Sales of Natural Gas (MMCFPD)
    4,062         4,215       3,792  
Sales of Natural Gas Liquids (MBPD)
    23         17       22  
Revenues From Liftings
                         
Liquids ($/Bbl)
  $ 55.97       $ 86.51     $ 65.01  
Natural Gas ($/MCF)
  $ 4.01       $ 5.19     $ 3.90  
 
                         
Worldwide Upstream
                         
Net Oil-Equivalent Production
(MBOEPD)3,4
                         
United States
    717         671       743  
International
    1,987         1,859       1,876  
           
Total
    2,704         2,530       2,619  
 
                         
U.S. Downstream
                         
Gasoline Sales (MBPD)5
    720         692       728  
Other Refined-Product Sales (MBPD)
    683         721       729  
           
Total Refined Product Sales (MBPD)
    1,403         1,413       1,457  
Sales of Natural Gas Liquids (MBPD)
    144         144       135  
Refinery Input (MBPD)
    899         891       812  
 
                         
International Downstream
                         
Gasoline Sales (MBPD)5
    555         589       581  
Other Refined-Product Sales (MBPD)
    1,296         1,427       1,446  
           
Total Refined Product Sales (MBPD)6
    1,851         2,016       2,027  
Sales of Natural Gas Liquids (MBPD)
    88         97       96  
Refinery Input (MBPD)
    979         967       1,021  
       
 
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
    58       70       65  
International
    463       450       433  
4  Includes production from oil sands, Net (MBPD):
    26       27       27  
5  Includes branded and unbranded gasoline.
                       
6  Includes sales of affiliates (MBPD):
    516       512       492  


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Liquidity and Capital Resources
Cash, cash equivalents and marketable securities Total balances were $8.8 billion and $9.6 billion at December 31, 2009 and 2008, respectively. Cash provided by operating activities in 2009 was $19.4 billion, compared with $29.6 billion in 2008 and $25.0 billion in 2007.
(GRAPH)
Cash provided by operating activities was net of contributions to employee pension plans of approximately $1.7 billion, $800 million and $300 million in 2009, 2008 and 2007, respectively. Cash provided by investing activities included proceeds and deposits related to asset sales of $2.6 billion in 2009, $1.5 billion in 2008 and $3.3 billion in 2007.
     Restricted cash of $123 million and $367 million associated with various capital-investment projects at December 31, 2009 and 2008, 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 approximately $5.3 billion in 2009, $5.2 billion in 2008 and $4.8 billion in 2007. In July 2009, the company increased its quarterly common stock dividend by 4.6 percent to $0.68 per share.
     Debt and capital lease obligations Total debt and capital lease obligations were $10.5 billion at December 31, 2009, up from $8.9 billion at year-end 2008.
     The $1.6 billion increase in total debt and capital lease obligations during 2009 included the net effect of a $5 billion public bond issuance, a $350 million issuance of tax-exempt Gulf Opportunity Zone bonds, a $3.2 billion decrease in commercial paper, and a $400 million payment of principal for Texaco Capital Inc. bonds that matured in January 2009. The company’s debt and capital lease obligations due within one year, consisting primarily of commercial paper and the current portion of long-term debt, totaled $4.6 billion at
December 31, 2009, down from $7.8 billion at year-end 2008. Of these amounts, $4.2 billion and $5.0 billion were reclassified to long-term at the end of each period, respectively. At year-end 2009, settlement of these obligations was not expected to require the use of working capital in 2010, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.
     At year-end 2009, the company had $5.1 billion in committed credit facilities with various major banks, which permit the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and also can be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at December 31, 2009. In addition, the company has an automatic shelf registration statement that expires in March 2010 for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company. The company intends to file a new shelf registration statement when the current one expires.
     The company has outstanding public bonds issued by Chevron Corporation, Chevron Corporation Profit Sharing/ Savings Plan Trust Fund, Texaco Capital Inc. and Union Oil Company of California. All of these securities are the obligations of, or guaranteed by, Chevron Corporation and are rated AA by Standard and Poor’s Corporation and Aa1 by Moody’s Investors Service. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 by Moody’s. All of these ratings denote high-quality, investment-grade securities.
     The company’s future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. The company believes that it has substantial borrowing capacity to meet unanticipated cash requirements and that during periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, it has the flexibility to increase borrowings and/or modify capital-spending plans to continue paying the common stock dividend and maintain the company’s high-quality debt ratings.
     Common stock repurchase program In September 2007, the company authorized the acquisition of up to $15 billion of its common shares at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. The program is for a period of up to three years (expiring in 2010) and may be discontinued at any time. The company did not acquire any shares during 2009 and does not plan to acquire any shares in the first quarter 2010. From the inception of the program, the company has acquired 119 million shares at a cost of $10.1 billion.


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

 
 
 
Capital and Exploratory Expenditures
                                                                             
                    2009                       2008                       2007  
                 
Millions of dollars   U.S.     Int’l.     Total       U.S.     Int’l.     Total       U.S.     Int’l.     Total  
             
Upstream – Exploration and Production
  $ 3,261     $ 13,848     $ 17,109       $ 5,516     $ 11,944     $ 17,460       $ 4,558     $ 10,980     $ 15,538  
Downstream – Refining, Marketing and Transportation
    1,910       2,511       4,421         2,182       2,023       4,205         1,576       1,867       3,443  
Chemicals
    210       92       302         407       78       485         218       53       271  
All Other
    402       3       405         618       7       625         768       6       774  
             
Total
  $ 5,783     $ 16,454     $ 22,237       $ 8,723     $ 14,052     $ 22,775       $ 7,120     $ 12,906     $ 20,026  
             
Total, Excluding Equity in Affiliates
  $ 5,558     $ 15,094     $ 20,652       $ 8,241     $ 12,228     $ 20,469       $ 6,900     $ 10,790     $ 17,690  
             

     Capital and exploratory expenditures Total expenditures for 2009 were $22.2 billion, including $1.6 billion for the company’s share of equity-affiliate expenditures and $2 billion for the extension of an upstream concession. In 2008 and 2007, expenditures were $22.8 billion and $20.0 billion, respectively, including the company’s share of affiliates’ expenditures of
$2.3 billion in both periods.
     Of the $22.2 billion of expenditures in 2009, about
three-fourths, or $17.1 billion, is related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2008 and 2007. International upstream accounted for about 80 percent of the worldwide upstream investment in 2009 and about
70 percent in 2008 and 2007, reflecting the company’s continuing focus on opportunities available outside the United States.
     (GRAPH)
     The company estimates that in 2010, capital and exploratory expenditures will be $21.6 billion, including $1.6 billion of spending by affiliates. About 80 percent of the total, or $17.3 billion, is budgeted for exploration and production activities, with $13.2 billion of this amount for projects outside the United States. Spending in 2010 is primarily targeted for exploratory prospects in the U.S. Gulf of Mexico and major development projects in Angola, Australia, Brazil, Canada, China, Nigeria, Thailand and the U.S. Gulf of Mexico. Also included is funding for base business improvements and focused appraisals in core hydrocarbon basins.
     Worldwide downstream spending in 2010 is estimated at $3.4 billion, with about $1.6 billion for projects in the
United States. Major capital outlays include projects under construction at refineries in the United States and South Korea and construction of gas-to-liquids facilities in support of associated upstream projects.
     Investments in chemicals, technology and other corporate businesses in 2010 are budgeted at $900 million. Technology investments include projects related to unconventional hydrocarbon technologies, oil and gas reservoir management, and gas-fired and renewable power generation.
     Noncontrolling interests The company had noncontrolling interests of $647 million and $469 million at December 31, 2009 and 2008, respectively. Distributions to noncontrolling interests totaled $71 million and $99 million in 2009 and 2008, respectively.
     Pension Obligations In 2009, the company’s pension plan contributions were $1.7 billion (including $1.5 billion to the U.S. plans and $200 million to the international plans). The company estimates contributions in 2010 will be approximately $900 million ($600 million for the U.S. plans and $300 million for the international plans). 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. Refer also to the discussion of pension accounting in “Critical Accounting Estimates and Assumptions,” beginning on page FS-18.
Financial Ratios
Financial Ratios
                           
    At December 31  
    2009       2008     2007  
       
Current Ratio
    1.4         1.1       1.2  
Interest Coverage Ratio
    62.3         166.9       69.2  
Debt Ratio
    10.3 %       9.3 %     8.6 %
       
     Current Ratio – current assets divided by current liabilities. 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 2009, the book value of inventory


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was lower than replacement costs, based on average acquisition costs during the year, by approximately $5.5 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. The company’s interest coverage ratio in 2009 was lower than 2008 and 2007 due to lower before-tax income.
     Debt Ratio – total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity. The increase in 2009 over 2008 and 2007 was primarily due to the increase in debt as a result of the $5 billion issuance of public bonds in 2009.
Guarantees, Off-Balance-
Sheet Arrangements and
    
(GRAPH)
Contractual Obligations, and Other Contingencies
Direct Guarantee
                                         
Millions of dollars   Commitment Expiration by Period  
                    2011–     2013–     After  
    Total     2010     2012     2014     2014  
 
Guarantee of non-
consolidated affiliate or
joint-venture obligation
  $ 613     $     $ 38     $ 77     $ 498  
 
     The company’s guarantee of approximately $600 million is associated with certain payments under a terminal use agreement entered into by a company affiliate. The terminal is expected to be operational by 2012. Over the approximate 16-year 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 any 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. The company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make future payments up to $300 million. Through the end of 2009, the company had paid $48 million under these indemnities and continues to be obligated for possible additional indemnification payments in the future.
     The company has also provided indemnities relating to contingent environmental liabilities related to assets origi-
nally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the period of Texaco’s ownership interest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims had to be asserted by February 2009 for Equilon indemnities and must be asserted no later than February 2012 for Motiva indemnities. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments. In February 2009, Shell delivered a letter to the company purporting to preserve unmatured claims for certain Equilon indemnities. 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.
     The amounts payable for the indemnities described in the preceding paragraph are to be net of amounts recovered from insurance carriers and others and net of liabilities recorded by Equilon or Motiva prior to September 30, 2001, for any applicable incident.
     In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. The acquirer of those assets shared in certain environmental remediation costs up to a maximum obligation of $200 million, which had been reached at December 31, 2009. Under the indemnification agreement, after reaching the $200 million obligation, Chevron is solely responsible until April 2022, when the indemnification expires. The environmental conditions or events that are subject to these indemnities must have arisen prior to the sale of the assets in 1997.
     Although the company has provided for known obligations under this indemnity that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity.
     Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline 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: 2010 – $7.5 billion; 2011 – $4.3 billion; 2012 – $1.4 billion; 2013 – $1.4 billion; 2014 – $1.0 billion; 2015 and after – $4.1 billion. A portion of these commitments may ultimately be shared with project


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

 
 
 

partners. Total payments under the agreements were approximately $8.1 billion in 2009, $5.1 billion in 2008 and $3.7 billion in 2007.
     The following table summarizes the company’s significant contractual obligations:
Contractual Obligations1
                                         
Millions of dollars   Payments Due by Period  
                    2011–     2013–     After  
    Total     2010     2012     2014     2014  
 
On Balance Sheet:2
                                       
Short-Term Debt3
  $ 384     $ 384     $     $     $  
Long-Term Debt3
    9,829             5,743       2,041       2,045  
Noncancelable Capital
Lease Obligations
    499       90       168       104       137  
Interest
    2,590       317       566       426       1,281  
Off-Balance-Sheet:
                                       
Noncancelable Operating Lease Obligations
    3,364       568       844       719       1,233  
Throughput and
Take-or-Pay Agreements
    15,130       6,555       3,825       819       3,931  
Other Unconditional Purchase Obligations4
    4,617       1,024       1,906       1,538       149  
 
1   Excludes contributions for pensions and other postretirement benefit plans. Information on employee benefit plans is contained in Note 21 beginning on page FS-52.
 
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 for 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 results of operations, consolidated financial position or liquidity in any single period.
 
3   $4.2 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 2011–2012 period.
 
4   Does not include obligations to purchase the company’s share of natural gas liquids and regasified natural gas associated with operations of the 36.4 percent-owned Angola LNG affiliate. The LNG plant is expected to commence operations in 2012 and is designed to produce 5.2 million metric tons of LNG and related natural gas liquids per year. Volumes and prices associated with these purchase obligations are neither fixed nor determinable.
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 discussed below 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 2009 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 2009.
     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.
     Virtually all derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet 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 from Chevron’s derivative commodity instruments in 2009 was a quarterly average decrease of $168 million in total assets and a quarterly average decrease of $104 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, which are recorded on the balance sheet at
December 31, 2009, as derivative commodity instruments in accordance with accounting standards for derivatives (ASC 815). VaR is the maximum 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 distribution 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,


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most of which can be liquidated or hedged effectively within one day. The table below 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, 2009 and 2008. The lower amounts in 2009 were primarily associated with a decrease in price volatility for these commodities during the year.
                   
Millions of dollars   2009       2008  
       
Crude Oil
  $ 17       $ 39  
Natural Gas
    4         5  
Refined Products
    19         45  
       
     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, 2009.
     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. Historically, under the terms of the swaps, net cash settlements were based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts. 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. At year-end 2009, the company had no interest rate swaps on floating-rate debt. The company’s only interest rate swaps on fixed-rate debt matured in January 2009 and the company had no interest rate swaps on
fixed-rate debt at year-end 2009.
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 Financial Information in Note 24 of the Consolidated Financial Statements, page FS-61, 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 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 50 pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE,
including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to pending lawsuits and claims is not determinable, but could be material to net income in any one period. The company no longer uses MTBE in the manufacture of gasoline in the United States.
     Ecuador Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador, brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpet’s ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40 million. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations.
     Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs bring the action, enacted in 1999, cannot be applied retroactively; third, that the claims are barred by the statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador. With regard to the facts, the company believes that the evidence confirms that Texpet’s remediation was properly conducted and that the remaining environmental damage reflects Petroecuador’s failure to timely fulfill its legal obligations and Petroecuador’s further conduct since assuming full control over the operations.
     In April 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $8 billion, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, health care systems and additional infrastructure for Petroecuador. The engineer’s report also asserted that an additional $8.3 billion could be assessed against Chevron for unjust enrichment. The engineer’s report is not binding on the court. Chevron also believes that the engineer’s work


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

was performed and his report prepared in a manner contrary to law and in violation of the court’s orders. Chevron submitted a rebuttal to the report in which it asked the court to strike the report in its entirety. In November 2008, the engineer revised the report and, without additional evidence, recommended an increase in the financial compensation for purported damages to a total of $18.9 billion and an increase in the assessment for purported unjust enrichment to a total of $8.4 billion. Chevron submitted a rebuttal to the revised report, which the court dismissed. In September 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 petitioned to be recused. In late September 2009, the judge was recused, and in October 2009, the full chamber of the provincial court affirmed the recusal, resulting in the appointment of a new judge. Chevron filed motions to annul all of the rulings made by the prior judge, but the new judge denied these motions. The court has completed most of the procedural aspects of the case and could render a judgment at any time. Chevron will continue a vigorous defense of any attempted imposition of liability.
     In the event of an adverse judgment, Chevron would expect to pursue its appeals and vigorously defend against enforcement of any such judgment; therefore, the ultimate outcome – and 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 engineer’s report, management does not believe the report has any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to estimate a reasonably possible loss (or a range of loss).
     Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude-oil fields, service stations, terminals, land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the
determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.
     Although the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations
(BAR CHART)

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.
     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   2009       2008     2007  
       
Balance at January 1
  $ 1,818       $ 1,539     $ 1,441  
Net Additions
    351         784       562  
Expenditures
    (469 )       (505 )     (464 )
       
Balance at December 31
  $ 1,700       $ 1,818     $ 1,539  
       
     Included in the $1,700 million year-end 2009 reserve balance were remediation activities at approximately 250 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 2009 was $185 million. 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.


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     Of the remaining year-end 2009 environmental reserves balance of $1,515 million, $820 million related to the company’s U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals), and pipelines. The remaining $695 million was associated with various sites in international downstream ($107 million), upstream ($369 million), chemicals ($149 million) and other businesses ($70 million). 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 2009 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.
     It is likely that the company will continue to incur additional liabilities, beyond those recorded, for environmental remediation relating to past operations. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.
     Under accounting standards for asset retirement obligations
(ASC 410), the fair value of a liability for an asset retirement obligation is recorded when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. The liability balance of approximately $10.2 billion for asset retirement obligations at year-end 2009 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 also to Note 23 on page FS-60, related to the company’s asset retirement obligations and the discussion of “Environmental Matters” on page FS-18.
     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 15 beginning on page FS-46 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. The company does not expect settlement of income tax liabilities associated with uncertain tax positions will have a material effect on its results of operations, consolidated financial position or liquidity.
     Suspended Wells The company suspends the costs of exploratory wells pending a final determination of the commercial potential of the related crude-oil and natural-gas fields. The ultimate disposition of these well costs is dependent on the results of future drilling activity or development decisions or both. At December 31, 2009, the company had approximately $2.4 billion of suspended exploratory wells included in properties, plant and equipment, an increase of $317 million from 2008. The 2008 balance reflected an increase of $458 million from 2007.
     The future trend of the company’s exploration expenses can be affected by amounts associated with well write-offs, including wells that had been previously suspended pending determination as to whether the well had found reserves that could be classified as proved. The effect on exploration expenses in future periods of the $2.4 billion of suspended wells at year-end 2009 is uncertain pending future activities, including normal project evaluation and additional drilling.
     Refer to Note 19, beginning on page FS-50, for additional discussion of suspended wells.
     Equity Redetermination For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude-oil and natural-gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for Chevron’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills, California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. For this range of settlement, Chevron estimates its maximum possible net before-tax liability at approximately $200 million, and the possible maximum net amount that could be owed to Chevron is estimated at about $150 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.
     Other Contingencies Chevron receives claims from and submits claims to customers; trading partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; and suppliers. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve.


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