10-K 1 f37829e10vk.htm FORM 10-K e10vk
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
 
þ  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2007
 
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
Chevron Corporation
(Exact name of registrant as specified in its charter)
 
         
Delaware   94-0890210   6001 Bollinger Canyon Road,
San Ramon, California 94583-2324
 
 
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification 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 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.  þ
 
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       Smaller reporting company o
(Do not check if a smaller
reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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 — $179,575,224,370 (As of June 30, 2007)
 
Number of Shares of Common Stock outstanding as of February 22, 2008 — 2,076,680,120
 
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
 
Notice of the 2008 Annual Meeting and 2008 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2008 Annual Meeting of Stockholders (in Part III)
 
 


 

 
TABLE OF CONTENTS
 
                 
Item
      Page No.
 
 
1.
    Business     3  
        (a) General Development of Business     3  
        (b) Description of Business and Properties     4  
       
    4  
       
    4  
       
    5  
       
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    24  
       
    25  
       
    25  
       
    26  
       
    27  
       
    28  
       
    29  
       
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    31  
       
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    31  
 
1A.
    Risk Factors     32  
 
1B.
    Unresolved Staff Comments     33  
 
2.
    Properties     33  
 
3.
    Legal Proceedings     33  
 
4.
    Submission of Matters to a Vote of Security Holders     33  
 
 
5.
    Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     34  
 
6.
    Selected Financial Data     34  
 
7.
    Management’s Discussion and Analysis of Financial Condition and Results of Operation     34  
 
7A.
    Quantitative and Qualitative Disclosures About Market Risk     34  
 
8.
    Financial Statements and Supplementary Data     34  
 
9.
    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure     35  
 
9A.
    Controls and Procedures     35  
        (a) Evaluation of Disclosure Controls and Procedures     35  
        (b) Management’s Report on Internal Control Over Financial Reporting     35  
        (c) Changes in Internal Control Over Financial Reporting     35  
 
9B.
    Other Information     35  
 
 
10.
    Directors, Executive Officers and Corporate Governance     36  
 
11.
    Executive Compensation     37  
 
12.
    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     37  
 
13.
    Certain Relationships and Related Transactions, and Director Independence     37  
 
14.
    Principal Accounting Fees and Services     37  
 
 
15.
    Exhibits, Financial Statement Schedules     38  
        Schedule II — Valuation and Qualifying Accounts     39  
        Signatures     40  
 EXHIBIT 12.1
 EXHIBIT 21.1
 EXHIBIT 23.1
 EXHIBIT 24.1
 EXHIBIT 24.2
 EXHIBIT 24.3
 EXHIBIT 24.4
 EXHIBIT 24.5
 EXHIBIT 24.6
 EXHIBIT 24.7
 EXHIBIT 24.8
 EXHIBIT 24.9
 EXHIBIT 24.10
 EXHIBIT 24.11
 EXHIBIT 24.12
 EXHIBIT 31.1
 EXHIBIT 31.2
 EXHIBIT 32.1
 EXHIBIT 32.2
 EXHIBIT 99.1


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CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
 
This Annual Report on Form 10-K of Chevron Corporation contains forward-looking statements relating to Chevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “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 our control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
 
Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are crude oil and natural gas prices; refining margins and marketing margins; chemicals margins; actions of competitors; timing of exploration expenses; 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 OPEC (Organization of Petroleum Exporting Countries); the potential liability for remedial actions under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; the potential liability resulting from pending or future litigation; the company’s acquisition or disposition of assets; gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” on pages 32 and 33 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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PART I
 
Item 1.     Business
 
(a)   General Development of Business
 
Summary Description of Chevron
 
Chevron Corporation,1 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 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. Chemical operations include the manufacture and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant oil additives.
 
On August 10, 2005, the company acquired Unocal Corporation (Unocal), an independent oil and gas exploration and production company. Discussion of the Unocal acquisition is in Note 2 on page FS-34.
 
A list of the company’s major subsidiaries is presented on pages E-4 and E-5. As of December 31, 2007, Chevron had approximately 65,000 employees (including about 6,000 service station employees). Approximately 31,000, or 48 percent, of the company’s employees were employed in U.S. operations.
 
Overview of Petroleum Industry
 
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 and 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 to 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 in the sale or acquisition of various goods or services in many national and international markets.
 
 
1 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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Operating Environment
 
Refer to pages FS-2 through FS-8 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company’s current business environment and outlook.
 
Chevron Strategic Direction
 
Chevron’s primary objective is to create value and achieve sustained financial returns from its operations that will enable it to outperform its competitors. As a foundation for achieving this objective, the company has established the following strategies:
 
      Strategies for Major Businesses
 
  •   Upstream — grow profitably in core areas, build new legacy positions and commercialize the company’s natural gas equity resource base while growing a high-impact global gas business
 
  •   Downstream — improve base-business 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 in important renewable sources of energy.
 
      Enabling Strategies Companywide
 
  •   Invest in people to achieve the company’s strategies
 
  •   Leverage technology to deliver superior performance and growth
 
  •   Build organizational capability to deliver world-class performance in operational excellence, cost reduction, capital stewardship and profitable growth
 
(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 Australasia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2007, and assets as of the end of 2007 and 2006 — for the United States and the company’s international geographic areas — are in Note 8 to the Consolidated Financial Statements beginning on page FS-37. In addition, similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Notes 11 and 12 on pages FS-40 to FS-42.
 
Capital and Exploratory Expenditures
 
Total reported expenditures for 2007 were $20 billion, including $2.3 billion for Chevron’s share of expenditures by affiliated companies, which did not require cash outlays by the company. In 2006 and 2005, expenditures were $16.6 billion and $11.1 billion, respectively, including the company’s share of affiliates’ expenditures of $1.9 billion and $1.7 billion in the corresponding periods. The 2005 amount excludes $17.3 billion for the acquisition of Unocal.
 
Of the $20 billion in expenditures for 2007, 78 percent, or $15.5 billion, related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2006 and 2005. International upstream accounted for about 70 percent of the worldwide upstream investment in each of the three years, reflecting the company’s continuing focus on opportunities that are available outside the United States.
 
In 2008, the company estimates capital and exploratory expenditures will be 15 percent higher at $22.9 billion, including $2.6 billion of spending by affiliates. About three-fourths of the total, or $17.5 billion, is budgeted for exploration and production activities, with $12.7 billion of that amount outside the United States.
 
Refer also to a discussion of the company’s capital and exploratory expenditures on page FS-12.
 
Upstream — Exploration and Production
 
The table on the following page summarizes the net production of liquids and natural gas for 2007 and 2006 by the company and its affiliates.


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Net Production of Crude Oil and Natural Gas Liquids and Natural Gas
 
                                                 
               
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)  
    2007     2006     2007     2006     2007     2006  
 
United States:
                                               
California
    221       224       205       207       97       101  
Gulf of Mexico
    214       224       118       114       576       661  
Texas (Onshore)
    153       150       77       79       457       425  
Other States
    155       165       60       62       569       623  
                                                 
Total United States
    743       763       460       462       1,699       1,810  
                                                 
Africa:
                                               
Angola
    179       164       171       156       48       47  
Nigeria
    129       144       126       139       15       29  
Chad
    32       35       31       34       4       4  
Republic of the Congo
    8       12       7       11       7       8  
Democratic Republic of the Congo
    3       3       3       3       2       2  
                                                 
Total Africa
    351       358       338       343       76       90  
                                                 
Asia-Pacific:
                                               
Thailand
    224       216       71       73       916       856  
Partitioned Neutral Zone (PNZ)1
    112       114       109       111       17       19  
Australia
    100       99       39       39       372       360  
Kazakhstan
    66       62       41       38       149       143  
Azerbaijan
    61       47       60       46       5       4  
Bangladesh
    47       21       2             275       126  
China
    26       26       22       23       22       18  
Philippines
    26       24       5       6       126       108  
Myanmar
    17       15                   100       89  
                                                 
Total Asia-Pacific
    679       624       349       336       1,982       1,723  
                                                 
Indonesia
    241       248       195       198       277       302  
Other International:
                                               
United Kingdom
    115       115       78       75       220       242  
Denmark
    63       68       41       44       132       146  
Argentina
    47       47       39       38       50       54  
Canada
    36       47       35       46       5       6  
Colombia
    30       29                   178       174  
Trinidad and Tobago
    29       29                   174       174  
Norway
    6       6       6       6       1       1  
Netherlands
    4       4       3       3       5       7  
Venezuela2
          7             3             21  
                                                 
Total Other International
    330       352       202       215       765       825  
                                                 
Total International
    1,601       1,582       1,084       1,092       3,100       2,940  
                                                 
Total Consolidated Operations
    2,344       2,345       1,544       1,554       4,799       4,750  
Equity Affiliates3
    248       213       212       178       220       206  
                                                 
Total Including Affiliates4,5
    2,592       2,558       1,756       1,732       5,019       4,956  
                                                 
 
1 Located between Saudi Arabia and Kuwait.
2 Through September 2006, LL-652 was reported as part of Venezuela consolidated operations. As of October 2006, LL-652 is reported under Equity Affiliates. See footnote 3 below.
3 Equity Affiliates represent Chevron’s share of production by affiliates, including Tengizchevroil (TCO) in Kazakhstan and Hamaca in Venezuela. Effective October 2006, the company converted its interests in Boscan and LL-652 operating service agreements in Venezuela to Empresas Mixtas (i.e., joint stock contractual structures), and these interests are accounted for as equity affiliates. LL-652 was previously reported as part of Venezuela consolidated operations, and Boscan was included in “other produced volumes.” See footnote 5 below.
4 Includes natural gas consumed in operations of 498 million and 475 million cubic feet per day in 2007 and 2006, respectively.
5 Does not include other produced volumes:
                                                 
Athabasca Oil Sands — net
      27         27         27         27         —         —  
Boscan Operating Service Agreement3
          82             82              


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As shown in the table on page 5, worldwide oil-equivalent production of 2.59 million barrels per day in 2007 was up 34,000 barrels per day from the prior year. Worldwide oil-equivalent production including “other produced volumes” (refer to footnote 5 to the table on page 5) was 2.62 million barrels per day, down about 2 percent from 2006. The decline was mostly attributable to the change in the Boscan operating service agreement in Venezuela to a joint-stock company in October 2006. Refer to the “Results of Operations” section beginning on page FS-6 for a detailed discussion of the factors explaining the 2005–2007 changes in production for crude oil and natural gas liquids and natural gas.
 
The company estimates that its average worldwide oil-equivalent production in 2008 will be approximately 2.65 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, and production that may have to be shut in due to weather conditions, civil unrest, 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 oil and gas development projects.
 
Average Sales Prices and Production Costs per Unit of Production
 
Refer to Table IV on page FS-66 for data about the company’s average sales price per barrel of crude oil and natural gas liquids and per thousand cubic feet of natural gas produced and the average production cost per oil-equivalent barrel for 2007, 2006 and 2005.
 
Gross and Net Productive Wells
 
The following table summarizes gross and net productive wells at year-end 2007 for the company and its affiliates:
 
Productive Oil and Gas Wells1 at December 31, 2007
 
                                 
    Productive2
    Productive2
 
    Oil Wells     Gas Wells  
    Gross     Net     Gross     Net  
 
United States:
                               
California
    25,029       23,305       176       44  
Gulf of Mexico
    1,600       1,375       1,104       893  
Other U.S.
    23,628       8,537       10,929       5,106  
                                 
Total United States
    50,257       33,217       12,209       6,043  
                                 
Africa
    2,190       748       8       3  
Asia-Pacific
    2,405       1,139       2,308       1,451  
Indonesia
    8,150       7,991       211       170  
Other International
    1,042       660       256       106  
                                 
Total International
    13,787       10,538       2,783       1,730  
                                 
Total Consolidated Companies
    64,044       43,755       14,992       7,773  
Equity in Affiliates
    1,072       375              
                                 
Total Including Affiliates
    65,116       44,130       14,992       7,773  
                                 
Multiple completion wells included above:
    967       587       456       340  
 
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.
 
Reserves
 
Table V, beginning on page FS-66, provides a tabulation of the company’s proved net oil and gas reserves, by geographic area, as of each year-end 2004 through 2007, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period. During 2007, the company provided oil and gas reserves estimates


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for 2006 to the Department of Energy, Energy Information Administration (EIA), that agree with the 2006 reserve volumes in Table V. This reporting fulfilled the requirement that such estimates are to be consistent with, and do not differ more than 5 percent from, the information furnished to the Securities and Exchange Commission in the company’s 2006 Annual Report on Form 10-K. During 2008, the company will file estimates of oil and gas reserves with the Department of Energy, EIA, consistent with the 2007 reserve data reported in Table V.
 
The net proved-reserve balances at the end of each of the three years 2005 through 2007 are shown in the table below:
 
Net Proved Reserves at December 31
 
                         
    2007     2006     2005  
 
Liquids* — Millions of barrels
                       
Consolidated Companies
    4,665       5,294       5,626  
Affiliated Companies
    2,422       2,512       2,374  
Natural Gas — Billions of cubic feet
                       
Consolidated Companies
    19,137       19,910       20,466  
Affiliated Companies
    3,003       2,974       2,968  
Total Oil-Equivalent — Millions of barrels
                       
Consolidated Companies
    7,855       8,612       9,037  
Affiliated Companies
    2,922       3,008       2,869  
 
* Crude oil, condensate and natural gas liquids
 
Acreage
 
At December 31, 2007, the company owned or had under lease or similar agreements undeveloped and developed oil and gas properties located throughout the world. The geographical distribution of the company’s acreage is shown in the following table.
 
Acreage1 at December 31, 2007
(Thousands of Acres)
 
                                                 
                Developed and
 
    Undeveloped2     Developed2     Undeveloped  
    Gross     Net     Gross     Net     Gross     Net  
 
United States:
                                               
California
    139       122       185       178       324       300  
Gulf of Mexico
    2,482       1,828       1,621       1,178       4,103       3,006  
Other U.S.
    3,800       3,012       5,884       2,588       9,684       5,600  
                                                 
Total United States
    6,421       4,962       7,690       3,944       14,111       8,906  
                                                 
Africa
    17,391       7,619       2,520       922       19,911       8,541  
Asia-Pacific
    52,006       23,660       5,847       2,630       57,853       26,290  
Indonesia
    9,109       5,894       382       340       9,491       6,234  
Other International
    35,688       20,022       2,397       664       38,085       20,686  
                                                 
Total International
    114,194       57,195       11,146       4,556       125,340       61,751  
                                                 
Total Consolidated Companies
    120,615       62,157       18,836       8,500       139,451       70,657  
Equity in Affiliates
    647       302       252       103       899       405  
                                                 
Total Including Affiliates
    121,262       62,459       19,088       8,603       140,350       71,062  
                                                 
 
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 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 2008, 2009 and 2010 if production is not established by certain required dates are 7,770, 10,860 and 4,288, respectively.


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Contract Obligations
 
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.
 
In the United States, the company is contractually committed to deliver to third parties and affiliates approximately 456 billion cubic feet of natural gas through 2010. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed U.S. reserves. These contracts include variable-pricing terms.
 
Outside the United States, the company is contractually committed to deliver to third parties a total of approximately 631 billion cubic feet of natural gas from 2008 through 2010 from Argentina, Australia, Canada, 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 and in some cases consider inflation or other factors. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed reserves in Argentina, Australia, Colombia, Denmark and the Philippines. The company plans to meet its Canadian contractual delivery commitments of 30 billion cubic feet through third-party purchases.
 
Development Activities
 
Details of the company’s development expenditures and costs of proved property acquisitions for 2007, 2006 and 2005 are presented in Table I on page FS-61.
 
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, 2007. 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 12/31/073     2007     2006     2005  
    Gross     Net     Prod.     Dry     Prod.     Dry     Prod.     Dry  
 
United States:
                                                               
California
    5       1       620             600             661        
Gulf of Mexico
    39       18       30       1       34       5       29       3  
Other U.S.
    11       10       225       4       317       6       256       4  
                                                                 
Total United States
    55       29       875       5       951       11       946       7  
                                                                 
Africa
    8       3       43             45       2       38        
Asia-Pacific
    13       4       223             235       1       150        
Indonesia
                374             258             107        
Other International
    4             52             43             79        
                                                                 
Total International
    25       7       692             581       3       374        
                                                                 
Total Consolidated Companies
    80       36       1,567       5       1,532       14       1,320       7  
Equity in Affiliates
                3             13             23        
                                                                 
Total Including Affiliates
    80       36       1,570       5       1,545       14       1,343       7  
                                                                 
 
1 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.
2 Includes completion of wells beginning August 2005 related to the former Unocal operations.
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 2007. 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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Exploration Activities
 
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, 2007. “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 12/31/073     2007     2006     2005  
    Gross     Net     Prod.     Dry     Prod.     Dry     Prod.     Dry  
 
United States:
                                                               
California
                                               
Gulf of Mexico
    12       5       4       7       9       8       14       8  
Other U.S.
                      1       7             5       6  
                                                                 
Total United States
    12       5       4       8       16       8       19       14  
                                                                 
Africa
    35       15       6       2       1             4       1  
Asia-Pacific
    1       1       14       10       18       7       10        
Indonesia
                1             2             5        
Other International
    3       1       5       2       6       3       7       4  
                                                                 
Total International
    39       17       26       14       27       10       26       5  
                                                                 
Total Consolidated Companies
    51       22       30       22       43       18       45       19  
Equity in Affiliates
                41             1             8        
                                                                 
Total Including Affiliates
    51       22       71       22       44       18       53       19  
                                                                 
 
1 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.
2 Includes completion of wells beginning August 2005 related to the former Unocal operations.
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 2007. Does not include wells for which drilling was completed at year-end 2007 and that were reported as suspended wells in Note 19 beginning on page FS-47. 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.
 
Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2007, 2006 and 2005 are presented in Table I on page FS-61.
 
Review of Ongoing Exploration and Production Activities in Key Areas
 
Chevron’s 2007 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-23.
 
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. In addition to the activities discussed, Chevron was active in other geographic areas, but those activities are considered less significant.


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Consolidated Operations
 
     
(WORLD MAP DIAGRAM)
 

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 natural gas equity resource base while growing a high-impact global gas business. The map on the left indicates Chevron’s primary areas of production and exploration as well as the potential target markets for the company’s natural gas resources.
 
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 during 2007 was 743,000 barrels per day, composed of 460,000 barrels of crude oil and natural gas liquids and 1.7 billion cubic feet of natural gas. Refer to Table V beginning on page FS-66 for a discussion of the net proved reserves and different hydrocarbon characteristics for the company’s major U.S. producing areas.
 
     
(CALIFORNIA MAP)
  California: The company has significant production in
the San Joaquin Valley. In 2007, average net oil-equivalent production was 221,000 barrels per day, composed of 200,000 barrels of crude oil, 97 million cubic feet of natural gas and 5,000 barrels of natural gas liquids. Approximately 80 percent of the crude-oil production is considered heavy oil (typically with API gravity lower than 22 degrees).
 


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(GULFMEX MAP)
 
Gulf of Mexico: Average net oil-equivalent production during 2007 for the company’s combined interests in the Gulf of Mexico shelf and deepwater areas, and the onshore fields in the region was 214,000 barrels per day. The daily oil-equivalent production comprised 105,000 barrels of crude oil, 576 million cubic feet of natural gas and 13,000 barrels of natural gas liquids.

During 2007, Chevron was engaged in various development and exploration activities in the deepwater Gulf of Mexico. Development work continued at the 58 percent-owned and operated Tahiti Field, where production start-up is expected in the third quarter 2009. Construction of
the spar hull and topsides was completed in 2007; however, installation of the spar hull was delayed for about one year when testing revealed a metallurgical problem with the mooring shackles. Six development wells were drilled in 2007, and flow-back tests for five of the six were completed during the year. Initial booking of proved undeveloped reserves occurred in 2003, and the transfer of these reserves into the proved developed category is anticipated near the time of production start-up. With an estimated production life of 30 years, Tahiti is designed to have a maximum total daily production of 125,000 barrels of crude oil and 70 million cubic feet of natural gas. The total cost for this project is estimated at $4.7 billion and includes a planned second phase of field development after start-up that involves additional wells and facility upgrades.
 
Also under development is the 75 percent-owned and operated Blind Faith discovery, in which the company increased its ownership from 63 percent in July 2007. Three development wells were drilled, and construction of the topsides and hull was completed in 2007. The project includes a subsea development plan, with tieback to a semisubmersible floating production facility that had an original daily-production design capacity of 45,000 barrels of crude oil and 45 million cubic feet of natural gas based on the initial three-well development program. A fourth development well and associated facility upgrades are planned to commence in the first half of 2008. The facility upgrades are planned to increase the daily capacity to 60,000 barrels of crude oil and 60 million cubic feet of natural gas. Initial daily total production, including the fourth well, is estimated at 45,000 to 60,000 barrels of crude oil and 45 million to 60 million cubic feet of natural gas. Proved undeveloped reserves for the project were recognized in 2005. Reclassification of the reserves to the proved developed category is anticipated near the time of production start-up in the second quarter 2008. The estimated production life of the field is approximately 20 years.
 
The company is also participating in the ultra-deep Perdido Regional Development. The project encompasses the installation of a producing host facility to service multiple fields, including Chevron’s 33 percent-owned Great White, 60 percent-owned Silvertip and 58 percent-owned Tobago. Chevron has a 38 percent interest in the Perdido Regional Host. All of these fields and the production facility are partner-operated. Activities during 2007 included facility construction and development drilling. First oil is expected in 2010, with the facility capable of handling 130,000 barrels of oil-equivalent per day. Proved undeveloped reserves related to the project were first recorded in 2006, and the phased reclassification of these reserves to the proved developed category is anticipated near the time of production start-up. The project has an expected life of approximately 25 years.
 
Deepwater exploration activities in 2007 included participation in 12 exploratory wells — six wildcat and six appraisal. Exploratory work included the following:
 
  •  Big Foot — 60 percent-owned and operated. A successful appraisal well was completed in January 2008.
 
  •  Jack — 50 percent-owned and operated. A second appraisal well is scheduled for completion in the second quarter 2008.
 
  •  Saint Malo — 41 percent-owned and operated. Located near the Jack discovery, a second appraisal well drilled in 2007 is scheduled for completion by the end of the first quarter 2008.
 
  •  Tubular Bells — 30 percent-owned and nonoperated working interest. The second appraisal well began drilling in 2007 and is scheduled for completion in the first quarter 2008.
 
  •  Knotty Head — 25 percent-owned and nonoperated working interest. Discovered in 2005, subsurface studies were in progress in early 2008.
 
  •  Puma — 22 percent-owned and nonoperated working interest. Two appraisal wells were drilled in 2007.

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  •  West Tonga — 21 percent-owned and nonoperated working interest. A successful discovery well was drilled in 2007.
 
At the end of 2007, the company had not yet 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 area, Chevron also continued the federal, state and local permitting process during 2007 and early 2008 for a proposed natural gas import terminal at Casotte Landing in Jackson County, Mississippi. In February 2007, the company received approval from the Federal Energy Regulatory Commission for the proposed terminal. The terminal would be located adjacent to the company’s Pascagoula Refinery and designed to process imported liquefied natural gas (LNG) for distribution to industrial, commercial and residential customers in Mississippi, Florida and the Northeast. The terminal would have an initial natural gas processing capacity of 1.3 billion cubic feet per day. The decision to construct a facility will be timed to align with the company’s LNG supply projects.
 
The company also has contractual rights to 1 billion cubic feet per day of regasification capacity beginning in 2009 at the third party-owned Sabine Pass LNG terminal that is expected to be commissioned in the second quarter 2008. Also in the Sabine Pass area in Louisiana, the company has a binding agreement to be one of the anchor shippers in a 3.2 billion-cubic-foot-per-day third party-owned natural gas pipeline. Chevron will have 1.6 billion cubic feet per day of capacity in the pipeline, of which 1 billion cubic feet per day is in a new pipeline and 600 million cubic feet per day is interconnecting capacity to an existing pipeline. The new pipeline system will provide access to Chevron’s Sabine and Bridgeline pipelines, which connect to the Henry Hub. The Henry Hub is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange (NYMEX) and is located on the natural gas pipeline system in Louisiana. Henry Hub interconnects to nine interstate and four intrastate pipelines.
 
Other U.S. Areas: Outside California and the Gulf of Mexico, the company manages operations across the mid-continental United States and Alaska. During 2007 in the Piceance Basin of northwestern Colorado, the company commenced development drilling in the basin’s tight-gas formation. Facilities to produce 50 million cubic feet of natural gas per day are expected to start up in 2009. The Piceance project, in which the company holds a 100 percent operated working interest, is scalable, and the work is planned to be completed in multiple phases over the 15- to 20-year project life. The plans include expanding facilities to a production capacity of 450 million cubic feet per day. The total cost for this project is estimated at $7.3 billion. Also during 2007, Chevron initiated redevelopment programs in three offshore fields in Alaska’s Cook Inlet, where the company operates 10 offshore platforms and five producing natural gas fields. The company also owns nonoperated working interest production and exploratory acreage at the White Hills prospect on the North Slope of Alaska. During 2007, the company’s production outside California and the Gulf of Mexico averaged 308,000 net oil-equivalent barrels per day, composed of 104,000 barrels of crude oil, 1 billion cubic feet of natural gas and 33,000 barrels of natural gas liquids.


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b)   Africa
 
     
(CENTRAL AFRICA MAP)
 

Angola: Chevron holds company-operated working interests in Blocks 0 and 14 and nonoperated working interests in Block 2 and the Fina Sonangol Texaco (FST) area. In 2007, daily net production was 179,000 barrels of oil-equivalent.

The 39 percent-owned Block 0 and 31 percent-owned Block 14 are off the west coast, north of the Congo River. In Block 0, the company operates in two areas — A and B — composed of 21 fields that produced 120,000 barrels per day of net liquids in 2007. The Block 0 concession extends through 2030.

Area A of Block 0 comprises 15 producing fields and averaged daily net production of approximately 65,000 barrels of crude oil and 1,000 barrels of liquefied petroleum gas (LPG) in 2007. This production includes volumes from the Banzala Field that produced first oil in June 2007. The development of the Mafumeira Field in Area A continued in 2007 and will target the northern portion of the field. Initial booking of proved
undeveloped reserves for this development occurred in 2003, and reclassification of proved undeveloped reserves into the proved developed category is anticipated near the time of first production expected in 2009. Maximum total daily production is expected to be approximately 30,000 barrels of crude oil in 2011.
 
Also in Area A, construction continued during 2007 on the Takula Gas Processing Platform and on projects for the Cabinda Gas Plant and the Flare and Relief Modification. These three projects, called the Area A Gas Management projects, are scheduled to start up in 2009 and are expected to eliminate the routine flaring of natural gas by reinjecting excess natural gas into various reservoirs.
 
In Area B of Block 0, average daily net production in 2007 from six producing fields was 47,000 barrels of crude oil and condensate and 7,000 barrels of LPG. Included in this production were volumes from the Sanha condensate natural gas utilization and Bomboco crude oil project that was completed in mid-2007. During 2007, a portion of the proved undeveloped reserves for this project was reclassified to the proved developed category.
 
In Block 14, net production in 2007 from the Benguela, Belize, Lobito, Tomboco, Kuito and Landana fields averaged 48,000 barrels of liquids per day. During 2007, development of the Benguela Belize-Lobito Tomboco (BBLT) project continued, with production of first oil at the Benguela and Tomboco fields. Further development drilling is expected to continue at all BBLT fields. Maximum total production for BBLT is estimated at 200,000 barrels of crude oil per day and is scheduled to occur in late 2008 or early 2009. Proved undeveloped reserves for Benguela and Belize were initially recognized in 1998 and for Lobito and Tomboco in 2000. Proved developed reserves for Belize and Lobito were recognized in 2006 and for Benguela and Tomboco in 2007. Additional BBLT reserves are expected to be reclassified to proved developed as project milestones are met. Development and production rights for these fields expire in 2027.
 
Another major project in Block 14 is the development of the Tombua and Landana fields. Construction of facilities continued in 2007. Production from the Landana North reservoir is utilizing the BBLT infrastructure. The maximum total daily production from Tombua and Landana of 100,000 barrels of crude oil is expected to occur in 2011. Proved undeveloped reserves were recognized for Tombua and Landana in 2001 and 2002, respectively. Initial reclassification from proved undeveloped to proved developed for Landana occurred in 2006 and continued in 2007. Further reclassification is expected between 2009 when the Tombua-Landana facilities are completed and 2012 when the drilling program is scheduled for completion. Development and production rights for these fields expire in 2028.
 
As of early 2008, the Negage project in Block 14 was under evaluation. Front-end engineering and design (FEED) for this project was expected to begin in late 2008, with the date of production start-up yet to be determined.


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Three exploration wells were drilled in Block 14 in 2007, one of which successfully appraised the 2006 Lucapa discovery. In the Malange Pinda prospect, one well resulted in a crude-oil discovery, and as of early 2008, evaluation was ongoing for the third well completed in the first quarter 2007. Appraisal drilling of the discoveries is expected to continue in 2008.
 
Chevron also has a 20 percent interest in a production-sharing contract (PSC) that covers Block 2, which is adjacent to the northwestern part of Angola’s coast south of the Congo River, and a 16 percent interest in the onshore FST area. Combined net production from these properties in 2007 was 3,000 barrels of liquids per day.
 
Refer also to page 23 for a discussion of affiliate operations in Angola.
 
Democratic Republic of the Congo: Chevron has an 18 percent nonoperated working interest in a concession for offshore properties. Daily net production from seven fields averaged 3,000 barrels of oil-equivalent in 2007.
 
Republic of the Congo: Chevron has a 32 percent nonoperated working interest in the Nkossa, Nsoko and Moho-Bilondo exploitation permits and a 29 percent nonoperated working interest in the Kitina and Sounda exploitation permits, all of which are offshore. Net production from the Republic of the Congo fields averaged 8,000 barrels of oil-equivalent per day in 2007. The Moho-Bilondo development continued in 2007, with first production expected in the second half 2008. The development plan calls for crude oil produced by subsea well clusters to flow into a floating processing unit. Maximum total daily production of 90,000 barrels of crude oil is expected in 2010. Proved undeveloped reserves were initially recognized in 2001. Transfer to the proved developed category is expected near the time of first production. Chevron’s development and production rights for Moho-Bilondo expire in 2030.
 
Two exploration wells were drilled in the Moho-Bilondo permit area during 2007 and were determined to have oil accumulations. As of early 2008, results continued under evaluation.
 
Angola-Republic of the Congo Joint Development Area: Chevron is the operator and holds a 31 percent interest in the Lianzi Development Area (formerly referenced as the 14K/A-IMI Unitization Zone), located in a joint development area shared equally between Angola and Republic of the Congo. In 2006, the development of the Lianzi area was approved by the committee of representatives from the two countries, and a conceptual field development plan was also submitted to this committee. In early 2007, one additional exploration well was drilled in the Lianzi area, but the results were considered subcommercial. As of early 2008, development studies and planning continued for this area.
 
Chad/Cameroon: Chevron is a nonoperating partner 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 a 21 percent interest in two affiliates that own the pipeline. Average daily net production from six fields in 2007 was 32,000 barrels of oil-equivalent, including volumes from a satellite field development project in the Maikeri Field that produced first oil in July 2007. In late 2007, a development application was submitted for another satellite field, Timbre, in the Doba area. The Chad producing operations are conducted under a concession agreement that expires in 2030.
 
Libya: Chevron is the operator and holds a 100 percent interest in the onshore Block 177 exploration license. Evaluation of seismic data was completed in late 2007, and an exploratory drilling program is scheduled for 2008.
 


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(NIGERIA MAP)
 
Nigeria: Chevron holds a 40 percent interest in 13 concessions predominantly in the onshore and near-offshore regions of the Niger Delta and varying interests in deepwater offshore blocks. In the Niger Delta, the company operates under a joint-venture arrangement with the Nigerian National Petroleum Corporation (NNPC), which owns a 60 percent interest. In 2007, net oil- equivalent production from 32 fields averaged 129,000 barrels per day. The daily oil-equivalent rate comprised 126,000 barrels of liquids and 15 million cubic feet of natural gas.

In the Niger Delta, Chevron has a 40 percent operated interest in the South Offshore Water Injection Project (SOWIP), an enhanced crude-oil recovery project in Oil Mining License (OML) 90 aimed at increasing production through water injection, natural-gas lift and production debottlenecking in the Okan and Delta fields. The upgraded Delta South Water Injection Platform (DSWIP), which is part of SOWIP, began water injection in March 2007 at a total daily rate of 100,000 barrels. The total maximum daily water injection rate
is expected to increase to 240,000 barrels in 2009 upon the laying of water injection pipelines. Crude-oil production at year-end 2007 was approximately 5,000 barrels per day, and maximum total production is expected to be 35,000 barrels per day in 2010. Initial recognition of proved reserves was made in 2005. Reclassification of additional proved undeveloped reserves to the developed category is expected to occur after the evaluation of the water injection performance. The estimated life of the project is 25 years.
 
During 2007, the company continued development activities of deepwater offshore projects. The 68 percent-owned and operated deepwater Agbami project in OML 127 and OML 128 is a subsea development with wells tied back to a floating production, storage and offloading (FPSO) vessel, which was delivered from South Korea in December 2007. Development drilling and completion operations started in 2006, and subsea installation of production equipment began in 2007. Maximum total daily production of 250,000 barrels of crude oil and natural gas liquids is anticipated within one year after start-up, which is expected by the third quarter 2008. The company initially recognized proved undeveloped reserves for Agbami in 2002. A portion of the proved undeveloped reserves is scheduled to be reclassified to proved developed in 2008 near production start-up. The expected field life is approximately 20 years. The total cost for this project is estimated at $5.4 billion.
 
The Aparo Field in OML 132 and OML 140 and the Bonga SW Field in OML 118 share a common geologic structure and are planned to be jointly developed. The geologic structure lies 70 miles offshore in 4,300 feet of water. A pre-unit agreement was executed between Chevron and the OML 118 partner group in 2006. Final terms for a unitization agreement are expected to be completed in mid-2008. In 2007, FEED and tendering of major contracts continued. Development will likely involve an FPSO vessel and subsea wells. Partners are expected to make the final investment decision in the second half 2008, with production start-up projected for 2012. Maximum total production of 150,000 barrels of crude oil per day is expected to be reached within one year of production start-up. The company recognized initial proved undeveloped reserves in 2006 for its approximate 20 percent nonoperated working interest in the unitized area. The expected production life of this project is 20 years.
 
The company holds a 30 percent nonoperated working interest in the Usan project, located offshore in OML 138 and designed to utilize an FPSO vessel. The company recognized proved undeveloped reserves in 2004. Production start-up is estimated for late 2011, before which time a portion of proved undeveloped reserves is expected to be reclassified to the proved developed category. Maximum total production of 180,000 barrels of crude oil per day is expected to be achieved within one year of start-up. The end date of the concession period will be determined after final regulatory approvals are obtained.
 
Chevron operates and holds a 95 percent interest in the Nsiko discovery on OML 140. As of early 2008, subsurface evaluations and field development planning were ongoing. An investment decision is contingent on negotiations concerning the level of Nigerian content in the project’s contracts.
 
The company has a 46 percent nonoperated interest in the Nnwa Field in OML 129, which contains a discovery that extends into two adjacent blocks not owned by Chevron. Commerciality is dependent upon resolution of the Nigerian Deepwater Gas fiscal regime and collaboration agreements with the adjacent blocks. A joint study was initiated in 2007 with owners in adjoining block OML 135 to progress technical and commercial evaluations.

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Chevron participated in two deepwater exploration wells during 2007. The Uge 2 well, drilled as an appraisal well to the Uge 1 discovery in Oil Prospecting License (OPL) 214, confirmed hydrocarbons. The company has a 20 percent nonoperated working interest in OPL 214. The second well was deemed noncommercial. Two additional deepwater exploration wells are planned in 2008.
 
Chevron also is involved in projects in the Niger Delta region that support the company’s strategic initiative to commercialize its significant natural gas resource base outside the United States. Construction is under way on the Phase 3A expansion of the Escravos Gas Plant (EGP), which is expected to start up in 2009. Phase 3A scope includes offshore natural gas gathering and compression infrastructure and a second gas processing facility, which potentially would increase processing capacity from 285 million to 680 million cubic feet of natural gas per day and increase LPG and condensate export capacity from 12,000 to 47,000 barrels per day. EGP Phase 3A is designed to process natural gas from the Meji, Delta South, Okan and Mefa producing fields. Proved undeveloped reserves associated with EGP Phase 3A were recognized in 2002. These reserves are expected to be reclassified to proved developed as various project milestones are reached and related projects are completed. The anticipated life of the project is 25 years. Chevron holds a 40 percent operated interest in this project.
 
Refer also to page 26 for a discussion of the planned gas-to-liquids facility at Escravos.
 
Chevron holds a 37 percent interest in the West African Gas Pipeline, which is designed to supply Nigerian natural gas to customers in Ghana, Benin and Togo for industrial applications and power generation. First gas is anticipated to be shipped by mid-2008, and facility completion, with a capacity of 170 million cubic feet of natural gas per day, is expected in the second-half 2008. Chevron is the managing sponsor in the West African Pipeline Company Limited affiliate, which constructed, owns and operates the 412-mile pipeline.
 
In March 2007, Chevron signed a shareholders’ agreement for a 19 percent interest in the OKLNG Free Zone Enterprise (OKLNG) affiliate, which will operate the Olokola LNG project. OKLNG plans to build a multitrain, 22 million-metric-ton-per-year natural gas liquefaction facility and marine terminal located in a free trade zone. The project entered FEED in 2006 and is expected to be implemented in phases, commencing with two trains having at least 11 million-metric-ton-per-year total capacity. Approximately 50 percent of the gas supplied to the plant is expected to be provided from the producing areas associated with Chevron’s joint-venture arrangement with NNPC (discussed earlier in this section).
 
Nigeria-São Tomé e Príncipe Joint Development Zone (JDZ): Chevron holds a 46 percent operated interest in JDZ Block 1. In 2006, the first exploration well encountered hydrocarbons. In 2008, technical studies are planned to determine the need for additional drilling and evaluate development alternatives.
 
c)   Asia-Pacific
 
     
(AUSTRALIA MAP)
 
Australia: During 2007, the average net oil-equivalent production from Chevron’s interests in Australia was 100,000 barrels per day, composed of 39,000 barrels of liquids and 372 million cubic feet of natural gas.

Chevron has a 17 percent nonoperated working interest in the North West Shelf (NWS) Venture offshore Western Australia. Daily net production from the project during 2007 averaged 29,000 barrels of crude oil and condensate, 369 million cubic feet of natural gas, and 5,000 barrels of LPG. Approximately 75 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. A fifth LNG train, which is intended to increase export capacity by more than 4 million metric tons per year, to more than 16 million, is expected to be commissioned in late 2008. The Angel natural gas field, where development is under way, and the North Rankin Redevelopment project will supply the fifth LNG train. Start-up of the fifth train is projected to accelerate production from the NWS fields. An investment decision by the company and its partners on the North Rankin Redevelopment project is expected in late 2008. The end of the NWS Venture concession period is 2034.
 
On Barrow and Thevenard islands off the northwest coast of Australia, Chevron operates crude oil producing facilities that had combined net production of 5,000 barrels per day in 2007. Chevron’s interests in these operations are 57 percent for Barrow and 51 percent for Thevenard.


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Also off the northwest coast of Australia, Chevron is the operator of the Gorgon development and has a 50 percent ownership interest across most of the Greater Gorgon Area. Chevron and its two joint-venture participants signed a Framework Agreement in 2005 that will enable the combined development of Gorgon and the nearby natural gas fields as one world-scale project. In 2007, the company received environmental regulatory approvals necessary for the development of the Greater Gorgon LNG project on Barrow Island using a two-train, 10 million-metric-ton-per-year LNG development plan. As of early 2008, the detailed environmental conditions were incorporated into the project’s updated optimization and engineering efforts for a three-train, 15 million-metric-ton-per-year LNG configuration, and activities to secure the necessary government approvals were under way. Natural gas for the project will be supplied from the Gorgon and Jansz fields. The Gorgon project has an expected economic life of at least 40 years.
 
Elsewhere in the Greater Gorgon Area during 2007, Chevron participated in four successful appraisal wells — two in the Browse Basin and two in the Carnarvon Basin. Chevron also participated in two exploration wells in the Carnarvon Basin, with Lady Nora resulting in a natural gas discovery and Snarf-1 expecting to be completed in 2008. As of early 2008, plans were also being developed to appraise the 67 percent-owned Clio and the 50 percent-owned Chandon natural gas discoveries. Concept studies continued in 2007 on the Wheatstone natural gas discovery, and a successful appraisal well was drilled late in the year. Further appraisal wells are planned to be drilled in the area in 2008.
 
At the end of 2007, the company had not recognized proved reserves for any of the Greater Gorgon Area fields. Recognition is contingent on securing sufficient LNG sales agreements and achieving other key project milestones. In 2007, the company signed a nonbinding Heads of Agreement (HOA) with GS Caltex, a Chevron affiliated company, to supply 250,000 metric tons of LNG annually from the Gorgon project. Combined with the nonbinding HOAs signed previously with three utility customers in Japan, volumes under the four HOAs totaled 4.5 million metric tons per year. As of early 2008, negotiations were continuing to finalize binding sales agreements on these HOAs. Purchases by each of these customers are expected to range from 300,000 metric tons per year to 1.5 million metric tons per year over 25 years.
 
     
EURASIA MAP
 
Azerbaijan: Chevron holds a 10 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 a 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” on page 28 for a discussion of the BTC operations.)

In 2007, the company’s daily net production from AIOC averaged 61,000 barrels of oil-equivalent. First production from Phase III of ACG development is targeted for the second quarter 2008. Total crude-oil production from the ACG project is expected to increase to about 940,000 barrels per day by the end of 2008 and to more than 1 million barrels per day in 2009. Proved undeveloped reserves for ACG are expected to be reclassified to proved developed reserves as wells are drilled and completed. The AIOC operations are conducted under a 30-year PSC that expires in 2024.
 
Kazakhstan: Chevron holds a 20 percent nonoperated working interest in the Karachaganak project that is being developed in phases. During 2007, Karachaganak net oil-equivalent production averaged 66,000 barrels per day, composed of 41,000 barrels of liquids and 149 million cubic feet of natural gas. In 2007, access to the Caspian Pipeline Consortium (CPC) and Atyrau-Samara (Russia) pipelines allowed Karachaganak sales of approximately 166,000 barrels per day (31,000 net barrels) of processed liquids at prices available in world markets. The remaining liquids were sold into Russian markets. During 2007, work continued on a fourth train that is designed to increase this export of processed liquids by 56,000 barrels per day (11,000 net barrels). The fourth train is expected to start up in 2009.
 
In 2007, the Karachaganak operator signed a 15-year natural gas sales agreement to deliver up to 1.6 billion cubic feet per day of sour gas to a Russian-Kazakh joint venture. Deliveries under the agreement commenced in September 2007. As of early 2008, Phase III development of Karachaganak continued under evaluation. The project could increase maximum total production to 335,000 barrels of liquids per day and 1.7 billion cubic feet of natural gas per day. Timing for the recognition of Phase III proved reserves is uncertain and depends on finalizing a viable Phase III project design.


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Project start-up is anticipated in 2012 or after, depending on achievement of project milestones. Karachaganak operations are conducted under a 40-year PSC that expires in 2038.
 
Refer also to pages 23 and 24 for a discussion of Tengizchevroil, a 50 percent-owned affiliate with operations in Kazakhstan.
 
Russia: Refer to page 24 for a discussion of the company’s interest in a Russian joint venture.
 
Bangladesh: Chevron is the operator of three onshore blocks, with a 98 percent interest in Blocks 12, 13 and 14 and operator of Block 7, in which the company holds a 43 percent interest. Net oil-equivalent production in 2007 averaged 47,000 barrels per day, composed of 275 million cubic feet of natural gas and 2,000 barrels of liquids. Production from the Bibiyana Field in Block 12 started in March 2007. The project is expected to reach maximum total production of 500 million cubic feet per day by late 2010. The development program included a gas processing plant with capacity of 600 million cubic feet per day and a natural gas pipeline. Initial proved reserves were recognized in 2005. In 2007, additional proved reserves were recognized based on development wells drilled during the year, and a portion of proved undeveloped reserves were reclassified to the proved developed category. Bibiyana operations are conducted under a PSC that expires in 2034.
 
     
ASIA-SOUTH MAP
 
Cambodia: Chevron operates and holds a 55 percent interest in the 1.2 million-acre Block A, located offshore in the Gulf of Thailand. A four-well exploration and appraisal program was completed in 2007. As of early 2008, the results and prospects for further drilling were being evaluated.

Myanmar: Chevron has a 28 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 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 2007 was 100 million cubic feet per day, or 17,000 barrels of oil-equivalent.
 
Thailand: Chevron has operated and nonoperated working interests in several different offshore blocks. The company’s net oil-equivalent production in 2007 averaged 224,000 barrels per day, composed of 71,000 barrels of crude oil and condensate and 916 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 six operating areas, and Blocks 10 through 13 and B12/27 produce crude oil, condensate and natural gas from 16 operating areas.
 
The company’s production of natural gas increased beginning in March 2007 with PTT’s commissioning of a third natural gas pipeline. In October 2007, the leases for Blocks 10 through 13 were extended from 2012 to 2022. In December 2007, the company signed a natural gas sales agreement that will increase daily contract quantity of natural gas from these blocks by 500 million cubic feet, to 1.2 billion, by 2012. In addition, this agreement is expected to enable the construction of a second central natural gas processing facility in the Platong area. The 70 percent-owned Platong Gas II project is designed to add 420 million cubic feet per day of processing capacity in the first quarter 2011. The company expects to recognize proved reserves throughout the project’s 12-year life as the wellhead platforms are installed.
 
Chevron has a 16 percent nonoperated working interest in Blocks 14A, 15A, 16A, G9/48 and G8/50, known collectively as the Arthit Field. First production from Arthit is planned for the second quarter 2008 and is expected to reach an estimated maximum total production of 330 million cubic feet of natural gas per day by the end of 2008. Proved undeveloped reserves were recorded for the first time in 2006. Reclassification of proved undeveloped reserves to the proved developed category is anticipated in 2008, near production start-up. The concessions that cover Arthit operations expire in 2040.


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In G9/48, one exploration well is required to be drilled by the first quarter 2009. Chevron also holds exploration interests in a number of blocks that are currently inactive, pending resolution of border issues between Thailand and Cambodia.
 
In late 2007, the company was granted the concession rights to four prospective offshore petroleum blocks in Thailand, which includes Block G8/50 (discussed earlier in this section). Chevron’s interest in the other three operated blocks, G4/50, G6/50 and G7/50, ranges from 35 percent to 75 percent.
 
Vietnam: The company is operator in two PSCs offshore southwest Vietnam in the northern part of the Malay Basin. Chevron has a 42 percent interest in one PSC that includes Blocks B and 48/95 and a 43 percent interest in the other PSC that has Block 52/97. Chevron also has a 50 percent operated interest in Block B122 offshore eastern Vietnam. No production occurred in these PSCs during 2007.
 
The Vietnam Gas Project is aimed at developing an area in the two Malay Basin PSCs to supply natural gas to state-owned PetroVietnam. In the third quarter 2007, PetroVietnam approved the revised development plan, joint development area and unitization agreement for the project. The project includes installation of wellhead and hub platforms, an FPSO vessel, infield pipelines and a central processing platform. The timing of first natural gas production is dependent upon the outcome of commercial negotiations. Maximum total production of approximately 500 million cubic feet of natural gas per day is projected within five years of start-up. Recognition of initial proved undeveloped reserves would follow execution of the gas sales agreements and project approval. The PSC for Blocks B and 48/95 and the PSC for Block 52/97 will expire in 2022 and 2029, respectively.
 
In Block 122, a planned seismic program was postponed in 2007 due to issues of territorial claim between Vietnam and China.
 
China: Chevron has nonoperated working interests of 33 percent in Blocks 16/08 and 16/19 located in the Pearl River Delta Mouth Basin, 25 percent in the QHD-32-6 Field in Bohai Bay and 16 percent in the unitized and producing BZ 25-1 Field in Bohai Bay Block 11/19. The company’s net oil-equivalent production in China during 2007 averaged 26,000 barrels per day, composed of 22,000 barrels of crude oil and condensate and 22 million cubic feet of natural gas.
 
Joint development of the HZ25-3 and HZ25-1 crude-oil fields in Block 16/19 commenced in the first quarter 2007. First production is expected in early 2009, reaching a maximum total daily production of approximately 14,000 barrels of crude oil late in the year. Chevron also has interests ranging from 36 percent to 50 percent in four prospective onshore natural gas blocks in the Ordos Basin totaling about 1.5 million acres. In December 2007, the company signed a 30-year PSC that became effective in February 2008 for the development of the Chuandongbei natural gas area in the onshore Sichuan Basin. The aggregate design input capacity of the proposed gas plants is expected to be 740 million cubic feet of natural gas per day. The company holds a 49 percent interest in the area.
 
Partitioned Neutral Zone (PNZ): Chevron holds a 60-year concession that expires in 2009 to produce crude oil from onshore properties in PNZ, which is located between Saudi Arabia and Kuwait. Negotiations to extend the concession period were ongoing in early 2008. Net production in PNZ for 2007 represented 4 percent of Chevron’s net barrels of oil-equivalent total.
 
Under the current concession, Chevron has the right to Saudi Arabia’s 50 percent interest in the hydrocarbon resource and pays a royalty and other taxes on volumes produced. During 2007, average net oil-equivalent production was 112,000 barrels per day, composed of 109,000 barrels of crude oil and 17 million cubic feet of natural gas. The second phase of a steamflood pilot project is expected to be completed in early 2009. This pilot is a unique application of steam injection into a carbonate reservoir and, if successful, could significantly increase recoverability of the heavy oil in place.
 
Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field located 50 miles offshore Palawan Island. Net oil-equivalent production in 2007 averaged 26,000 barrels per day, composed of 126 million cubic feet of natural gas and 5,000 barrels of condensate. Chevron also develops and produces steam resources under an agreement with the National Power Corporation, a Philippine government — owned company. The combined generating capacity is 637 megawatts.


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d)   Indonesia
 
     
(map)
  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 Mountain Front Kuantan PSC. Other subsidiaries operate four PSCs in the Kutei Basin, East Kalimantan and one PSC in the Tarakan Basin, Northeast Kalimantan. These interests range from 80 percent to 100 percent. Chevron also has nonoperated working interests in a joint venture in South Natuna Sea Block B and in the NE Madura III block in the East Java Sea Basin. Chevron’s interests in these PSCs range from 25 percent to 40 percent. In January 2008, Chevron relinquished its 35 percent nonoperated working interest
in the Donggala PSC in the Kutei Basin. In West Java, Chevron wholly owns a power generation company that operates the Darajat geothermal contract area in Garut, West Java, with a total capacity of 259 megawatts. This includes the Darajat III 110-megawatt unit that was placed online in July 2007. Chevron also operates a 95 percent-owned 300-megawatt cogeneration facility in support of CPI’s operation in North Duri and the wholly owned Salak geothermal field, located in West Java, with a total capacity of 377 megawatts.
 
The company’s net oil-equivalent production in 2007 from all of its interests in Indonesia averaged 241,000 barrels per day. The daily oil-equivalent rate comprised 195,000 barrels of crude oil and 277 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. An expansion area, Area 12, is targeted for start-up in late 2008. Maximum total daily production is estimated at 34,000 barrels of crude oil in 2012. Two other areas have been identified for possible sequential expansions. Proved undeveloped reserves for North Duri were recognized in previous years, and reclassification from proved undeveloped to proved developed is scheduled to occur during various stages of sequential completion. The Rokan PSC expires in 2021.
 
A drilling campaign continued through 2007 in South Natuna Sea Block B, with first oil produced from the Kerisi Field in December 2007. First production of LPG from the Belanak Field was achieved in April 2007. Additional development drilling in the North Belut Field is scheduled to begin in mid-2008, with first production expected in 2009.
 
In January 2007, Chevron combined the development of the Gendalo and Gehem deepwater natural gas fields located in the Kutei Basin into a single project with one development concept. In August 2007, the company submitted final development plans to the government of Indonesia. Approvals are expected during the first-half 2008. The Bangka natural gas project was under evaluation in 2007 and will likely be developed in parallel with Gendalo and Gehem. The development timing is partially dependent on government approvals, market conditions and the achievement of key project milestones. The company holds an 80 percent operated interest in these projects.
 
As of early 2008, the development concept for the 50 percent-owned and operated Sadewa project in the Kutei Basin remained under evaluation. Also in the Kutei Basin, the development of the Seturian Field project continued in 2007, with first production anticipated in late 2008. The project is designed to supply natural gas to a state-owned refinery.


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e)   Other International Areas
 
     
(map)
 
Argentina: Chevron holds an operated interest in 17 concessions and one exploratory block in the Neuquen and Austral basins. Working interests range from 19 percent to 100 percent. Net oil-equivalent production in 2007 averaged 47,000 barrels per day, composed of 39,000 barrels of crude oil and 50 million cubic feet of natural gas. Chevron also holds a 14 percent interest in the Oleoductos del Valle S.A. pipeline.

In 2007, three exploratory wells were drilled in the Austral Basin, and two were successful.

Brazil: Chevron holds working interests ranging from 20 percent to 52 percent in three deepwater blocks. None of the blocks had production in 2007.

In Block BC-4, located in the Campos Basin, the company is the operator and has a 52 percent interest in the Frade Field. In 2007, major construction activities included work to convert a crude-oil tanker to an FPSO vessel and the manufacture of subsea systems and flowlines for the project. Subsea installation activities began in early 2008. Proved undeveloped reserves were recorded for
the first time in 2005. Partial reclassification of proved undeveloped reserves to the proved developed category is anticipated upon production start-up in early 2009. Estimated maximum total production of 90,000 oil-equivalent barrels per day is anticipated in 2011. The concession that involves the Frade project expires in 2025.
 
The company concentrates its exploration efforts in the Campos and Santos basins. In the partner-operated Campos Basin Block BC-20, two areas — 38 percent-owned Papa-Terra and 30 percent-owned Maromba — have been retained for development following the end of the exploration phase of this block. In 2006, a Papa-Terra field development plan was submitted to the government, and as of early 2008 this plan was still under evaluation. In Maromba as of early 2008, a pilot production system was under consideration, with first oil projected for 2013. Elsewhere in Campos, the company relinquished its 30 percent nonoperated working interest in BM-C-4. In the 20 percent-owned and partner-operated Santos Basin Block BS-4, development options for the Atlanta and Oliva fields were under evaluation.
 
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 178 million cubic feet of natural gas, or 30,000 barrels of oil-equivalent, in 2007. During the year, new dehydration facilities were constructed that enabled natural gas exports to Venezuela beginning in January 2008.
 
Trinidad and Tobago: The company has a 50 percent nonoperated working interest in four blocks in the East Coast Marine Area offshore Trinidad, which include the Dolphin and Dolphin Deep producing natural gas fields and the Starfish discovery. Net production from Dolphin and Dolphin Deep in 2007 averaged 174 million cubic feet of natural gas per day, or 29,000 barrels of oil-equivalent.
 
In May 2007, a domestic natural gas sales agreement was signed for the Trinidad Incremental Gas project. The agreement includes the delivery of 220 million cubic feet per day for 11 years with an option for a four-year extension. Drilling operations started in late 2007 at the Dolphin platform. First gas for the project is expected in 2009, ramping up to maximum total production of 220 million cubic feet of natural gas per day in early 2010. Reserves were initially booked in 2006. In 2007, additional proved reserves were recorded, and some proved undeveloped reserves were reclassified to the proved developed category. Further reclassifications are expected in 2008, following the drilling of additional development wells.
 
Chevron also holds a 50 percent operated interest in the Manatee area of Block 6d. In early 2007, an agreement was signed by the governments of Venezuela and Trinidad and Tobago to unitize the Loran Field in Venezuela and the Manatee area. Negotiations are expected to continue in 2008 to achieve a field-specific unitization treaty.
 
Venezuela: Chevron holds interest in two affiliates located in western Venezuela and one affiliate in the Orinoco Belt. The company also operates in two exploratory blocks offshore Plataforma Deltana, with working interests of 60 percent in Block 2 and 100 percent in Block 3. In Block 2, which includes the Loran natural gas field, a conceptual offshore development plan was completed in 2007. In Block 3, Chevron discovered natural gas in 2005 that is in close proximity to Loran. Both Block 3 and Loran will provide a possible supply source for Venezuela’s first LNG train. Seismic work elsewhere in Block 3 was completed in 2007. Chevron also has a 100 percent interest in the Cardon III


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block, located north of the Maracaibo producing region. Seismic in this block, which has natural gas potential, was acquired in 2007 and is planned to be processed in 2008. Petróleos de Venezuela, S.A. (PDVSA) has the option to increase its ownership in all three company-operated blocks up to 35 percent upon declaration of commerciality.
 
Refer also to page 24 for a discussion of affiliate operations in Venezuela.
 
Canada: The company has nonoperated working interests of 27 percent in the Hibernia Field offshore eastern Canada and 20 percent in the Athabasca Oil Sands Project (AOSP), a 60 percent operated interest in the Ells River “In Situ” Oil Sands Project, a 28 percent operated interest in the Hebron project and exploration acreage in the Mackenzie Delta, Beaufort Sea and the Orphan Basin. Excluding volumes mined at the AOSP, average net oil-equivalent production during 2007 was 36,000 barrels per day, composed of 35,000 barrels of crude oil and natural gas liquids and 5 million cubic feet of natural gas. Substantially all of the production was from the Hibernia Field. At AOSP, bitumen mined and upgraded to synthetic crude oil averaged 27,000 net barrels per day.
 
At AOSP, the first phase of an expansion project, with an estimated total project cost of $10.2 billion, is being designed to upgrade an additional 100,000 barrels of bitumen into synthetic crude oil per day. The expansion would increase total AOSP design capacity to more than 255,000 barrels of bitumen per day in 2010. Preliminary work is under way to determine the feasibility of additional expansion projects.
 
The Ells River project consists of heavy oil leases of more than 85,000 acres. The area contains significant volumes with the potential for recovery using Steam Assisted Gravity Drainage, a proven technology that employs steam and horizontal drilling to extract the bitumen through wells rather than through mining operations. During 2007, a successful appraisal drilling program involving 66 wells was completed. Follow-up appraisal activities are planned in 2008, with a similar number of wells and a small 2-D and 3-D seismic program.
 
The potential development at Hebron stalled in 2006 after unsuccessful negotiations with the provincial government of Newfoundland and Labrador. In mid-2007, the Hebron partners executed a nonbinding memorandum of understanding with the government that outlined fiscal, equity and local-benefit terms associated with the Hebron project. Execution of formal agreements is expected during 2008.
 
Exploratory activities are expected to continue during 2008 in the Mackenzie Delta and the Orphan Basin.
 
     
(map)
 
Denmark: Chevron holds a 15 percent nonoperated working interest in the Danish Underground Consortium (DUC), which produces crude oil and natural gas from 15 fields in the Danish North Sea and has a 12 percent interest in each of four exploration licenses. Net oil-equivalent production in 2007 from DUC averaged 63,000 barrels per day, composed of 41,000 barrels of crude oil and 132 million cubic feet of natural gas.

Faroe Islands: Chevron has a 40 percent interest in five offshore blocks and is the operator. During 2007, the company acquired a 2-D seismic survey over License 008, located near the Rosebank/Lochnagar discovery in the United Kingdom.

Greenland: In October 2007, Chevron was awarded a 29 percent nonoperated working interest in an exploration license in Block 4 offshore West Greenland in the Baffin Basin. The planned four-year work program includes seismic acquisition, and geologic, engineering and environmental studies.
 
Netherlands: Chevron is the operator and holds interests ranging from 34 percent to 80 percent in nine blocks in the Dutch sector of the North Sea. The company’s daily net production from eight producing fields averaged 3,000 barrels of crude oil and 5 million cubic feet of natural gas. Production start-up at the first stage of the A/B Gas Project from Block A12 occurred in December 2007 at an initial daily total rate of 60 million cubic feet of natural gas. As of early 2008, the second stage of the project was under evaluation.
 
Norway: At the 8 percent-owned and partner-operated Draugen Field, the company’s net production during 2007 was 6,000 barrels of oil-equivalent per day. In the 40 percent-owned and partner-operated PL397, seismic survey data was processed in 2007. Acquisition of additional seismic data is planned for 2008. Exploration activities are expected to continue in 2008 in various license areas.
 
United Kingdom: The company’s average net oil-equivalent production in 2007 from nine offshore fields was 115,000 barrels per day, composed of 78,000 barrels of crude oil and 220 million cubic feet of natural gas. Most of the


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production was from the 85 percent-owned and operated Captain Field and the 32 percent-owned and jointly-operated Britannia Field.
 
As of early 2008, development activities were continuing at the Britannia satellite fields Callanish and Brodgar, in which Chevron holds 17 percent and 25 percent nonoperated working interests, respectively. Production start-up from these two fields is expected to occur in late 2008. Together, these fields are expected to achieve maximum total daily production of 25,000 barrels of crude oil and 133 million cubic feet of natural gas several months after both fields start up. Proved undeveloped reserves were initially recognized in 2000. In 2006, proved undeveloped reserves were reclassified to the proved developed category. This project has an expected production life of approximately 15 years.
 
In exploration activities, the Alder discovery west of the Britannia Field was being evaluated in early 2008 and is likely to be developed as a tieback to existing infrastructure. The company has a 70 percent operated interest in the project, which is expected to start up and reach maximum total daily production rates of 9,000 barrels of crude oil and 80 million cubic feet of natural gas in 2012. The timing of the initial proved-reserves recognition was also under evaluation in early 2008. This project has an expected production life of approximately nine years.
 
At the Rosebank/Lochnagar discovery west of the Shetland Islands, an appraisal program consisting of three wells and a sidetrack was completed in 2007. All four wellbores encountered hydrocarbons, and an evaluation for commerciality was under way in early 2008. Evaluation continued of a successful natural gas production test at the Tormore well that is also in the West of Shetlands gas trend. During 2007, another successful appraisal well was drilled in the Clair Phase 2 area.
 
Equity Affiliate Operations
 
Angola: In addition to the exploration and producing activities in Angola, Chevron participates in the Angola LNG project, for which the company and partners made a final investment decision at the end of 2007. The LNG plant will be designed with a capacity to process 1 billion cubic feet of natural gas per day and will provide a commercial option for Angola’s natural gas resources. Chevron has a 36 percent interest in the Angola LNG affiliate. Construction began in early 2008 on the 5.2 million-metric-ton-per-year onshore LNG plant that is located in the northern part of the country. Plant start-up is expected in 2012. At the end of 2007, the company made an initial booking of proved natural gas reserves for the producing operations associated with this LNG project. The life of the LNG plant is estimated to be in excess of 20 years.
 
Kazakhstan: The company holds a 50 percent interest in Tengizchevroil (TCO), which is 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 2007 from these fields averaged 176,000 barrels per day, composed of 144,000 barrels of crude oil and natural gas liquids and 193 million cubic feet of natural gas.
 
TCO is undergoing a significant expansion composed of two integrated projects referred to as the Second Generation Plant (SGP) and Sour Gas Injection (SGI). At a total combined cost of approximately $7.2 billion, these projects are designed to increase TCO’s crude-oil production capacity to 540,000 barrels per day during the second half of 2008.
 
SGP involves the construction of a large processing train for treating crude oil and the associated sour gas (i.e., high in sulfur content). The SGP design is based on the same conventional technology employed in the existing processing trains. Proved undeveloped reserves associated with SGP were recognized in 2001. Wells were drilled, deepened and/or completed since 2002 in the Tengiz and Korolev reservoirs to produce volumes required for the new SGP train. Reserves associated with the project were reclassified to the proved developed category. Over the next decade, ongoing field development is expected to result in the reclassification of additional proved undeveloped reserves to proved developed.
 
SGI involves taking a portion of the sour gas separated from the crude-oil production at the SGP processing train and reinjecting it into the Tengiz reservoir. Chevron expects that SGI will have two key effects. First, SGI will reduce the sour gas processing capacity required at SGP, thereby increasing liquid production capacity and lowering the quantities of sulfur and gas that would otherwise be generated. Second, SGI is expected over time to increase production efficiency and recoverable volumes as the injected gas maintains higher reservoir pressure and displaces oil toward producing wells. The company anticipates recognizing additional proved reserves associated with the SGI expansion in late 2008. The primary SGI risks include uncertainties about compressor performance associated with injecting high-pressure sour gas and subsurface responses to injection.


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Initial production from the first phase of the SGI/SGP expansion projects occurred in late 2007. This first phase increased production capacity by 90,000 barrels per day, to approximately 400,000, in January 2008.
 
As of early 2008, essentially all of TCO’s production was being 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. Also in early 2008, CPC was seeking stockholder approval for an expansion to accommodate increased TCO volumes beginning in 2009. Expanded rail-car loading and rail-export facilities, designed to transport most of the incremental SGI/SGP production prior to the CPC expansion, started operation during 2007. As of early 2008, other alternatives were also being explored to increase export capacity.
 
Venezuela: Chevron has a 30 percent interest in the Hamaca heavy oil production and upgrading project located in Venezuela’s Orinoco Belt, a 39 percent interest in the Petroboscan affiliate that operates the Boscan Field, and a 25 percent interest in the Petroindependiente affiliate that operates the LL-652 Field. The company’s average net oil-equivalent production during 2007 from these affiliates was 72,000 barrels per day, composed of 68,000 barrels of crude oil and 27 million cubic feet of natural gas.
 
The Hamaca project has a total design capacity for processing and upgrading 190,000 barrels per day of heavy crude oil (8.5 degrees API gravity) into 180,000 barrels of lighter, higher-value crude oil (26 degrees API gravity). In February 2007, the president of Venezuela issued a decree announcing the government’s intention for PDVSA to increase its ownership in all Orinoco Heavy Oil Associations effective May 1, 2007, including Chevron’s 30 percent-owned Hamaca project, to a minimum of 60 percent. In December 2007, Chevron executed a conversion agreement and signed a charter and by-laws with a PDVSA subsidiary that provided for Chevron to retain its 30 percent interest in the Hamaca project. The new entity, Petropiar, commenced activities in January 2008.
 
The Boscan Field is located onshore western Venezuela. A 3-D seismic program was acquired in 2007 that is expected to guide future development activities in South Boscan. The water-injection pressure-maintenance project was expanded to include four wells converted to injectors in 2007, and four new injectors are planned to be drilled in 2008 and 2009. The LL-652 Field is located in Lake Maracaibo.
 
Russia: As of early 2008, Chevron and JSC Gazprom Neft continued to negotiate the final agreements for exploration and development activities in two licensed areas in the Yamal-Nenets region of western Siberia. Once the agreement is finalized, Chevron is expected to hold a 49 percent interest in the Northern Taiga Neftegaz LLC affiliate, which will operate in the licensed areas. Exploration and delineation activities are planned for 2008 on both licenses.
 
Sales of Natural Gas and Natural Gas Liquids
 
The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. Outside the United States, substantially all of the natural gas sales are from the company’s producing interests in Australia, Bangladesh, Kazakhstan, Indonesia, Latin America, the Philippines, Thailand and the United Kingdom. Substantially all of the company’s natural gas liquids sales 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 natural gas and natural gas liquids sales volumes. Refer also to “Contract Obligations” on page 8 for information related to the company’s contractual commitments for the sale of crude oil and natural gas.


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Downstream — Refining, Marketing and Transportation
 
Refining Operations
 
At the end of 2007, the company’s refining system consisted of 19 fuel refineries and an asphalt plant. The company operated nine of these facilities, and 11 were operated by affiliated companies. The daily refinery inputs for 2005 through 2007 for the company and affiliate refineries are as follows:
 
Petroleum Refineries: Locations, Capacities and Inputs
(Capacities and inputs in thousands of barrels per day; includes equity share in affiliates)
 
                                             
        December 31, 2007                    
          Operable
    Refinery Inputs  
Locations   Number     Capacity     2007     2006     2005  
 
Pascagoula
  Mississippi     1       330       285       337       263  
El Segundo
  California     1       260       222       258       230  
Richmond
  California     1       243       192       224       233  
Kapolei
  Hawaii     1       54       51       50       50  
Salt Lake City
  Utah     1       45       42       39       41  
Other1
        1       80       20       31       28  
                                             
Total Consolidated Companies — United States
    6       1,012       812       939       845  
                                         
Pembroke
  United Kingdom     1       210       212       165       186  
Cape Town2
  South Africa     1       110       72       71       61  
Burnaby, B.C.
  Canada     1       55       49       49       45  
                                             
Total Consolidated Companies — International
    3       375       333       285       292  
Affiliates3
  Various Locations     11       728       688       765       746  
                                             
Total Including Affiliates — International
    14       1,103       1,021       1,050       1,038  
                                         
Total Including Affiliates — Worldwide
      20         2,115         1,833         1,989         1,883  
                                         
 
1 Asphalt plants in Perth Amboy, New Jersey, and Portland, Oregon. The Portland plant was sold in February 2005.
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 2008.
3 Chevron sold its 31 percent interest in the Nerefco Refinery in the Netherlands in March 2007. This decreased the company’s share of operable capacity by about 124,000 barrels per day.
 
In the first quarter 2008, the company sold its 4 percent ownership interest in an affiliate that owned a refinery in Abidjan, Côte d’Ivoire, decreasing the company’s share of operable capacity by about 2,000 barrels per day.
 
Average crude oil distillation capacity utilization during 2007 was 86 percent, compared with 90 percent in 2006. This decrease generally resulted from unplanned downtime to repair damage resulting from fires in the crude units at the Richmond and Pascagoula refineries during 2007. This impact was partially offset by an improvement in capacity utilization at the Pembroke, U.K., refinery, which had unplanned downtime in 2006. The crude unit at the Pascagoula Refinery was back in service in February 2008. Despite the outage at Pascagoula, the company was able to maintain uninterrupted product supplies to customers through the use of other feedstocks in its gasoline-producing facilities at the refinery. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 85 percent in 2007, compared with 99 percent in 2006, and cracking and coking capacity utilization averaged 78 percent and 86 percent in 2007 and 2006, respectively. Cracking and coking units, including fluid catalytic cracking units, are the primary facilities used in fuel refineries to convert heavier products into gasoline and other light products.
 
The company’s fuel refineries in the United States, Europe, Canada, South Africa and Australia produce low-sulfur fuels. In 2007, Singapore Refining Company, the company’s 50 percent-owned affiliate, began an upgrade project at its 290,000-barrel-per-day refinery in Singapore to produce diesel fuels that meet Euro IV specifications.
 
In 2007, the company completed modifications at its refineries in El Segundo, California, to enable the processing of heavier crude oils into gasoline, diesel and other light products, and in the United Kingdom to increase the capability to process Caspian-blend crude oils. In October 2007, the company approved plans to construct a $500 million Continuous Catalyst Regeneration unit at the Pascagoula, Mississippi, refinery, which is expected to increase gasoline production by 10 percent, or 600,000 gallons per day, by mid-2010. Design and engineering for a project to increase the


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flexibility to process lower API-gravity crude oils at the company’s Richmond, California, refinery continued in 2007. Other upgrade projects at the El Segundo Refinery were being evaluated in early 2008.
 
In late 2007, GS Caltex, the company’s 50 percent-owned affiliate, completed commissioning of new facilities associated with a $1.5 billion upgrade project at the 680,000-barrel-per-day Yeosu refining complex in South Korea. This project is expected to increase the yield of high-value refined products by 33,000 barrels per day, add 15,000 barrels of new lubricant base oil production and reduce feedstock costs through an increase in the refinery’s ability to process heavy oil.
 
Chevron owns a 5 percent interest in Reliance Petroleum Limited, a company formed by Reliance Industries Limited to own and operate a new export refinery being constructed in Jamnagar, India. The refinery is expected to begin operation by year-end 2008, with a crude-oil capacity of 580,000 barrels per day. Chevron has future rights to increase its equity ownership to 29 percent.
 
Chevron processes imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 87 percent of Chevron’s U.S. refinery inputs in 2007 and 2006, respectively.
 
Gas-to-Liquids
 
Through the Sasol Chevron Global 50-50 Joint Venture, the company is pursuing gas-to-liquids (GTL) opportunities in several countries.
 
In Nigeria, Chevron and the Nigerian National Petroleum Corporation are developing a 34,000-barrel-per-day GTL facility at Escravos designed to process natural gas supplied from the Phase 3A expansion of the Escravos Gas Plant (EGP). As of early 2008, approximately 90 percent of engineering and procurement activities had been completed. Chevron has a 75 percent interest in the plant, which is expected to be operational by the end of the decade. Refer also to page 16 for a discussion on the EGP Phase 3A expansion.


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Marketing Operations
 
The company markets petroleum products throughout much of the world. The principal brands for identifying these products are “Chevron,” “Texaco” and “Caltex.” The table below identifies the company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ending December 31, 2007.
 
Refined Products Sales Volumes1
(Thousands of Barrels per Day)
 
                   
    2007   2006   2005
 
United States
                 
Gasolines
    728     712     709
Jet Fuel
    271     280     291
Gas Oils and Kerosene
    221     252     231
Residual Fuel Oil
    138     128     122
Other Petroleum Products2
    99     122     120
                   
Total United States
    1,457     1,494     1,473
                   
International3
                 
Gasolines
    581     595     662
Jet Fuel
    274     266     258
Gas Oils and Kerosene
    730     776     781
Residual Fuel Oil
    271     324     404
Other Petroleum Products2
    171     166     147
                   
Total International
    2,027     2,127     2,252
                   
Total Worldwide3
    3,484     3,621     3,725
                   
 
                             
1
  Includes buy/sell arrangements. Refer to Note 13 on page FS-42.           50       217  
2
  Principally naphtha, lubricants, asphalt and coke.                        
3
  Includes share of equity affiliates’ sales:     492       492       498  
 
In the United States, the company markets under the Chevron and Texaco brands. The company supplies directly or through retailers and marketers approximately 9,700 Chevron- and Texaco-branded motor vehicle retail outlets, concentrated in the mid-Atlantic, southern and western states. Approximately 550 of the outlets are company-owned or -leased stations.
 
Outside the United States, Chevron supplies directly or through retailers and marketers approximately 15,400 branded service stations, including affiliates. In British Columbia, Canada, the company markets under the Chevron brand. In Europe, the company markets primarily in the United Kingdom and Ireland under the Texaco brand. In West Africa, the company operates or leases to retailers in Benin, Cameroon, Côte d’Ivoire, Nigeria, Republic of the Congo and Togo. In these countries, the company uses the Texaco brand. The company also operates across the Caribbean, Central America and South America, with a significant presence in Brazil, using the Texaco brand. In the Asia-Pacific region, southern, central and east 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, using the GS Caltex brand. The company’s 50 percent-owned affiliate in Australia operates using the Caltex, Caltex Woolworths and Ampol brands.
 
The company continued the marketing and sale of retail fuels networks and individual service station sites, focusing on selected areas outside the United States. In 2007, the company sold its fuels marketing businesses in Belgium, the Netherlands and Luxembourg and its retail fuels business in Uruguay. The company also sold its interest in about 500 individual service station sites, primarily in the United Kingdom and Latin America. Since the beginning of 2003, the company has sold its interests in about 3,300 service station sites. The vast 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 1,000 airports, representing a worldwide market share of about 11 percent, and is a leading marketer of jet fuels in the United States. The company also markets an extensive line of lubricant and coolant products under brand names that include Havoline, Delo, Ursa, Meropa and Taro.


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Transportation Operations
 
Pipelines: Chevron owns and operates an extensive system of crude oil, refined products, chemicals, natural gas liquids and natural gas pipelines 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.
 
Pipeline Mileage at December 31, 2007
 
         
    Net Mileage1  
United States:
       
Crude Oil2
    2,853  
Natural Gas
    2,275  
Petroleum Products3
    7,053  
         
Total United States
    12,181  
International:
       
Crude Oil2
    700  
Natural Gas
    768  
Petroleum Products3
    426  
         
Total International
    1,894  
         
Worldwide
    14,075  
         
 
     
1
  Partially owned pipelines are included at the company’s equity percentage.
2
  Includes gathering lines related to the transportation function. Excludes gathering lines related to U.S. and international production activities.
3
  Includes refined products, chemicals and natural gas liquids.
 
During 2007, the company led the development of a natural gas gathering pipeline serving the Piceance Basin in northwest Colorado; participated in the successful installation of the 55-mile Amberjack-Tahiti lateral pipeline on the seafloor of the U.S. Gulf of Mexico; and completed a pipeline running from the U.S. Gulf of Mexico subsea to the Fourchon Terminal in southern Louisiana. The company is also leading the expansion of the West Texas liquefied natural gas pipeline system that is expected to be operational in late 2008. In addition, the company continued with its project to expand capacity by about 2 billion cubic feet at its Keystone natural gas storage facility, which is expected to be completed in 2009.
 
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 2007, CPC transported an average of approximately 700,000 barrels of crude oil per day, including 545,000 barrels per day from Kazakhstan and 155,000 barrels per day from Russia. For information related to the possible expansion of the CPC pipeline, refer to page 24.
 
The company has a 9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, whose pipeline transports Azerbaijan International Operating Company (AIOC) (owned 10 percent by Chevron) production from Baku, Azerbaijan, through Georgia to deepwater port facilities in Ceyhan, Turkey. The BTC pipeline has a crude-oil capacity of 1 million barrels per day and transports the majority of the AIOC production. Another crude oil production export route is the Western Route Export Pipeline, wholly owned by AIOC, with crude-oil capacity to transport 145,000 barrels per day from Baku, Azerbaijan, to the terminal at Supsa, Georgia.
 
For information on projects under way related to the West African Gas Pipeline, refer to page 16.


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Tankers: At any given time during 2007, the company had approximately 80 vessels chartered on a voyage basis, or for a period of less than one year. Additionally, all tankers in Chevron’s controlled seagoing fleet were utilized during 2007. The following table summarizes cargo transported on the company’s controlled fleet.
 
Controlled Tankers at December 31, 2007
 
                                 
    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
    1       0.3       19       28.1  
Time Chartered*
     —         —         24         14.3  
                                 
Total
    4       1.1       44       43.5  
 
One year or more.
 
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. In 2007, the company’s U.S. flag fleet was 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. Three U.S.-flagged product tankers, each capable of carrying 300,000 barrels of cargo, are scheduled for delivery from 2008 through 2010.
 
The foreign-flagged vessels were 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. Refined products were also transported by tanker worldwide. During 2007, the company took delivery of one new double-hulled tanker, with a total capacity of 500,000 barrels, and one U.S.-flagged product tanker capable of carrying 300,000 barrels of cargo. The company also returned a 1 million-barrel-capacity crude tanker at the end of its lease.
 
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. In 2005, Chevron placed orders for two company-owned LNG tankers.
 
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. This has raised the demand for double-hull tankers. At the end of 2007, 100 percent of the company’s owned and bareboat-chartered fleet was double-hulled. The company is a member of many oil-spill-response cooperatives in areas in which it operates around the world.
 
Chemicals
 
Chevron Phillips Chemical Company LLC (CPChem) is equally owned with ConocoPhillips Corporation. At the end of 2007, CPChem owned or had joint venture interests in 30 manufacturing facilities and six research and technical centers in Belgium, China, Puerto Rico, Qatar, Saudi Arabia, Singapore, South Korea and the United States.
 
In 2007, CPChem completed construction on the integrated, world-scale styrene facility in Al Jubail, Saudi Arabia. Jointly owned with the Saudi Industrial Investment Group (SIIG), commercial production is expected to commence in mid-2008. The styrene facility is located adjacent to CPChem and SIIG’s existing aromatics complex in Al Jubail. Also during 2007, CPChem secured final approval for a third petrochemical project in Al Jubail. Construction began in early 2008, with expected completion in 2011. Preliminary studies are focused on the construction of a world-scale olefins unit as well as related downstream units to produce polyethylene, polypropylene, 1-hexene and polystyrene. In the first half of 2008, commercial operations are expected to begin for the Americas Styrenics joint venture between CPChem and Dow Chemical Company that combines CPChem’s styrene and polystyrene operations with Dow’s polystyrene operations.
 
CPChem continued construction during 2007 on the 49 percent-owned Q-Chem II project in Mesaieed, Qatar. The project includes a 350,000-metric-ton-per-year polyethylene plant and a 345,000-metric-ton-per-year normal alpha olefins plant — each utilizing CPChem proprietary technology — and is located adjacent to the existing Q-Chem I complex. Q-Chem II also includes a separate joint venture to develop a 1.3 million-metric-ton-per-year ethylene cracker at Qatar’s Ras Laffan Industrial City, in which Q-Chem II owns 54 percent of the capacity rights. CPChem and its


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partners expect to start up the plants in the first half of 2009. Construction also began during 2007 of the Ryton® polyphenylene sulfide manufacturing facility in Texas, with completion scheduled for 2009.
 
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 provides additives for lubricating oil 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. Oronite has completed construction of the new carboxylate detergent unit in France. This facility will produce new sulfur-free detergent components for marine engine applications and low-sulfur components for automotive engine oil applications. Full commercial production from this facility is expected to commence early in the second quarter 2008.
 
Other Businesses
 
Mining
 
Chevron’s U.S.-based mining company produces and markets coal, molybdenum, rare earth minerals and calcined petroleum coke. Sales occur in both U.S. and international markets.
 
In 2007, the company’s coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), changed its name to Chevron Mining Inc. (CMI) and merged with Molycorp Inc., another Chevron mining subsidiary, to form a single Chevron mining entity. The company owns and operates two surface coal mines, McKinley, in New Mexico, and Kemmerer, in Wyoming, and one underground coal mine, North River, in Alabama. Sales of coal from CMI’s wholly owned mines were 12 million tons, down about 1 million tons from 2006.
 
At year-end 2007, CMI controlled approximately 214 million tons of proven and probable coal reserves in the United States, including reserves of environmentally desirable low-sulfur coal. The company is contractually committed to deliver between 11 million and 12 million tons of coal per year through the end of 2009 and believes it will satisfy these contracts from existing coal reserves.
 
In addition to the coal operations, Chevron owns and operates the Questa molybdenum mine in New Mexico and the Mountain Pass rare earth mine in California. At year-end 2007, CMI controlled approximately 57 million pounds of proven molybdenum reserves at Questa and 241 million pounds of proven and probable rare earth reserves at Mountain Pass.
 
Chevron also owns a 33 percent interest in Sumikin Molycorp, a manufacturer of neodymium compounds, located in Japan, and a 50 percent interest in Youngs Creek Mining Company LLC, a joint venture to develop a coal mine in northern Wyoming. The company also owns the Chicago Carbon Company, a producer and marketer of calcined petroleum coke, which operates a 250,000-ton-per-year petroleum coke calciner facility in Lemont, Illinois.
 
Power Generation
 
Chevron’s power generation business develops and operates commercial power projects and owns 15 power assets located in the United States and Asia. The company manages the production of more than 2,334 megawatts of electricity at 11 facilities it owns through joint ventures. The company operates gas-fired cogeneration facilities that use waste heat recovery to produce additional electricity or to support industrial thermal hosts. A number of the facilities produce steam for use in upstream operations to facilitate production of heavy oil.
 
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 pages 19 and 20, and the Research and Technology section below, respectively.
 
Chevron Energy Solutions
 
Chevron Energy Solutions (CES) is a wholly owned subsidiary that provides public institutions and businesses with projects designed to increase energy efficiency and reliability, reduce energy costs, and utilize renewable and alternative power technologies. CES has energy-saving projects installed in more than a thousand buildings nationwide. Major


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projects completed by CES in 2007 include energy efficiency installations for the state of Colorado government facilities and a 1.1 megawatt solar system at California’s Fresno State University.
 
Research and Technology
 
The company’s Energy Technology Company (ETC) supports Chevron’s upstream and downstream businesses. ETC provides technology and competency support in earth sciences; reservoir and production engineering; drilling and completions; facilities engineering; health, environment and safety; refining; technical computing; strategic planning; and organizational capability.
 
Technology Ventures Company manages investments and projects in emerging energy technologies and their integration into Chevron’s core businesses. Its activities are managed through four business units: Venture Capital, Biofuels, Hydrogen and Emerging Energy.
 
Information Technology Company integrates computing, telecommunications, data management, security and network technology to provide a standardized digital infrastructure for Chevron’s global operations.
 
During 2007, the company entered into research alliances with Texas A&M University, with focus on the production and conversion of crops for biofuels from cellulose, and the Colorado Center for Biorefining and Biofuel, with focus on conversion technologies. The company also has research alliances with the University of California, Davis and the Georgia Institute of Technology that are focused on converting cellulosic biomass into transportation fuels.
 
Chevron’s research and development expenses were $562 million, $468 million and $316 million for the years 2007, 2006 and 2005, respectively.
 
Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate successes are not certain. Although not all initiatives may prove to be economically viable, the company’s overall investment in this area is not significant to the company’s consolidated financial position.
 
Environmental Protection
 
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. Chevron expects more environment-related regulations in the countries where it has operations. Most of the costs of complying with the many laws and regulations pertaining to its operations are embedded in the normal costs of conducting business.
 
In 2007, the company’s U.S. capitalized environmental expenditures were approximately $350 million, representing approximately 5 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 facilities. The expenditures are predominantly in the upstream and downstream segments and relate mostly to air- and water-quality projects and activities at the company’s refineries, oil and gas producing facilities, and marketing facilities. For 2008, the company estimates U.S. capital expenditures for environmental control facilities will be approximately $580 million. The future annual capital costs of fulfilling this commitment are uncertain and will be governed by several factors, including future changes to regulatory requirements.
 
Further information on environmental matters and their impact on Chevron and on the company’s 2007 environmental expenditures, remediation provisions and year-end environmental reserves are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages FS-16 and FS-17.
 
Web Site Access to SEC Reports
 
The company’s Internet Web site can be found 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 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, www.sec.gov.


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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 exposed to the effects of changing commodity prices.
 
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 crude-oil prices. Except in the ordinary course of running an integrated petroleum business, Chevron does not seek to hedge its exposure to price changes. A significant, persistent decline in crude-oil prices may have a material adverse effect on its results of operations and its capital and exploratory expenditure plans.
 
The scope of Chevron’s business will decline if the company does not successfully develop resources.
 
The company is in an extractive business; therefore, if Chevron is not successful in replacing the crude oil and natural gas it produces with good prospects for future production, 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.
 
The company’s operations could be disrupted by natural or human factors.
 
Chevron operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations and facilities are therefore subject to disruption from either natural or human causes, including hurricanes, floods and other forms of severe weather, war, civil unrest and other political events, fires, earthquakes, and explosions, any of which could result in suspension of operations or harm to people or the natural environment.
 
Chevron’s business subjects the company to liability risks.
 
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. Any of these activities could result in liability, 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.
 
Political instability could harm Chevron’s business.
 
The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates. As has occurred in the past, actions could be taken by governments to increase public ownership of the company’s partially or wholly owned businesses and/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, 2007, 26 percent of the company’s proved reserves were located in Kazakhstan. The company also has significant interests in Organization of Petroleum Exporting Countries (OPEC) — member countries including Angola, Indonesia, Nigeria and Venezuela. Twenty-eight percent of the company’s net proved reserves, including affiliates, were located in OPEC countries at December 31, 2007.


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Regulation of greenhouse gas emissions could increase Chevron’s operational costs and reduce demand for Chevron’s products.
 
Management believes it is reasonably likely that the scientific and political attention to issues concerning the existence and extent of climate change, and the role of human activity in it, will continue, with the potential for further regulation that affects the company’s operations. Although uncertain, these developments could increase costs or reduce the demand for the products the company sells. The company’s production and processing operations (e.g., the production of crude oil at offshore platforms and the processing of natural gas at liquefied natural gas facilities) typically result in emissions of greenhouse gases. Likewise, emissions arise from midstream and downstream operations, including crude oil transportation and refining. Finally, although beyond the control of the company, the use of passenger vehicle fuels and related products by consumers also results in greenhouse gas emissions that may be regulated.
 
International agreements, domestic legislation and regulatory measures to limit greenhouse gas emissions are currently in various phases of discussion or implementation. These include the Kyoto Protocol, proposed federal legislation and current state-level actions. Some of the countries in which Chevron operates have ratified the Kyoto Protocol, and the company is currently complying with greenhouse gas emissions limits within the European Union. Although resolutions supporting “cap and trade” systems have been introduced in the U.S. Congress, no bill restricting greenhouse gas emissions has been passed to date.
 
In California, the Global Warming Solutions Act became effective on January 1, 2007. This law caps California’s greenhouse gas emissions at 1990 levels by 2020; directs the Air Resources Board, the responsible state agency, to determine certain greenhouse gas emissions in and outside California to adopt mandatory reporting rules for significant sources of greenhouse gases; delegates to the agency the authority to adopt compliance mechanisms (including market-based approaches); and permits a one-year extension of the targets under extraordinary circumstances. Related regulatory activity is under way within the California Public Utilities Commission. The Air Resources Board and the California Energy Commission are also in the process of developing a “Low Carbon Fuel Standard” for transportation fuels used in California, as directed by Governor Arnold Schwarzenegger. The company extracts crude oil and natural gas, operates refineries, and markets and sells gasoline, diesel and jet fuel in California. The extent to which the state and local agencies’ regulations will affect the company’s California operations was not known as of early 2008.
 
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 the Securities Exchange Act Industry Guide No. 2 (“Disclosure of Oil and Gas Operations”) is also contained in Item 1 and in Tables I through VII on pages FS-61 to FS-74. Note 12, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-42.
 
Item 3.     Legal Proceedings
 
In January 2008, Chevron agreed to pay the state of New York a $162,500 civil penalty in connection with a February 2006 oil spill at the company’s facility in Perth Amboy, New Jersey.
 
Item 4.     Submission of Matters to a Vote of Security Holders
 
None.


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PART II
 
Item 5.    Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
The information on Chevron’s common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-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  
 
Oct. 1 – Oct. 31, 2007
    4,225,293       92.09       4,038,000        
Nov. 1 – Nov. 30, 2007
    10,455,696       86.46       10,200,000        
Dec. 1 – Dec. 31, 2007
    8,375,829       90.82       8,221,763        
                                 
Total Oct. 1 – Dec. 31, 2007
    23,056,818       89.08       22,459,763       (2 )
                                 
 
(1)  Includes 42,494 common shares repurchased during the three-month period ended December 31, 2007, 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 554,561 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, 2007.
 
(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 will occur over a period of up to three years and may be discontinued at any time. As of December 31, 2007, 23,530,209 shares had been acquired under this program for $2.1 billion.
 
Item 6.    Selected Financial Data
 
The selected financial data for years 2003 through 2007 are presented on page FS-60.
 
Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operation
 
The index to Management’s Discussion and Analysis, 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 7 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-36.
 
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
 
Chevron Corporation’s Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the company’s “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of December 31, 2007, have concluded that as of December 31, 2007, the company’s disclosure controls and procedures were effective and designed to provide reasonable assurance that material information relating to the company and its consolidated subsidiaries required to be included in the company’s periodic filings under the Exchange Act would be made known to them by others within those entities.
 
(b)    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 Rules 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, 2007.
 
The effectiveness of the company’s internal control over financial reporting as of December 31, 2007, 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, 2007, 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 28, 2008
 
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
 
D.J. O’Reilly
  61   Chairman of the Board and Chief Executive Officer (since 2000)   Chief Executive Officer
P.J. Robertson
  61   Vice Chairman of the Board (since 2002) President of Chevron Overseas
  Petroleum Inc. (2000 to 2002)
  Policy, Government and Public Affairs; Human Resources
J.E. Bethancourt
  56   Executive Vice President (since 2003) Vice President of Human Resources
  (2001 to 2003)
  Technology; Chemicals; Mining; Health, Environment and Safety
G.L. Kirkland
  57   Executive Vice President (since 2005) President of Chevron Overseas
  Petroleum Inc. (2002 to 2004)
President of Chevron U.S.A. Production  Company (2000 to 2002)
  Worldwide Exploration and Production Activities and Global Gas Activities, including Natural Gas Trading
J.S. Watson
  51   Executive Vice President (since 2008) Vice President and President of Chevron
  International Exploration and Production Company
  (2005 through 2007)
Vice President and Chief Financial
  Officer (2000 through 2004)
  Business Development; Mergers and Acquisitions; Strategic Planning; Project Resources Company
M.K. Wirth
  47   Executive Vice President (since 2006) President of Global Supply and Trading
  (2004 to 2006)
President of Marketing, Asia, Middle East and Africa Marketing
  Business Unit (2001 to 2004)
  Global Refining, Marketing, Lubricants, and Supply and Trading, excluding Natural Gas Trading
S.J. Crowe
  60   Vice President and Chief Financial
  Officer (since 2005)
Vice President and Comptroller
  (from 2000 through 2004)
  Finance
C.A. James
  53   Vice President and General Counsel
  (since 2002)
  Law
 
The information on Directors appearing under the heading “Election of Directors — Nominees for Directors” in the Notice of the 2008 Annual Meeting of Stockholders and 2008 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 2008 Annual Meeting of Stockholders (the “2008 Proxy Statement”), is incorporated by reference in this Annual Report on Form 10-K.
 
The information contained under the heading “Stock Ownership Information — Section 16(a) Beneficial Ownership Reporting Compliance” in the 2008 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
 
The information contained under the heading “Board Operations — Business Conduct and Ethics Code” in the 2008 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
 
The information contained under the heading “Board Operations — Board Committee Membership and Functions” in the 2008 Proxy Statement is incorporated by reference in 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 appearing under the headings “Executive Compensation” and “Directors’ Compensation” in the 2008 Proxy Statement is incorporated herein by reference in this Annual Report on Form 10-K.
 
The information contained under the heading “Board Operations — Board Committee Membership and Functions” in the 2008 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
 
The information appearing under the heading “Management Compensation Committee Report” in the 2008 Proxy Statement is incorporated herein by reference in 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 2008 Proxy Statement shall not be deemed “filed” for purposes of Section 18 of the Exchange Act nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933.
 
Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
The information appearing under the heading “Stock Ownership Information — Security Ownership of Certain Beneficial Owners and Management” in the 2008 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
 
The information contained under the heading “Equity Compensation Plan Information” in the 2008 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
 
Item 13.    Certain Relationships and Related Transactions, and Director Independence
 
The information appearing under the heading “Board Operations — Transactions With Related Persons” in the 2008 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
 
Item 14.    Principal Accounting Fees and Services
 
The information appearing under the heading “Ratification of Independent Registered Public Accounting Firm” in the 2008 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.


37


 

 
PART IV
 
Item 15.     Exhibits, Financial Statement Schedules
 
(a) The following documents are filed as part of this report:
 
              (1)  Financial Statements:
 
     
    Page(s)
 
Report of Independent Registered Public Accounting Firm — PricewaterhouseCoopers LLP
  FS-26
Consolidated Statement of Income for the three years ended December 31, 2007
  FS-27
Consolidated Statement of Comprehensive Income for the three years ended December 31, 2007
  FS-28
Consolidated Balance Sheet at December 31, 2007 and 2006
  FS-29
Consolidated Statement of Cash Flows for the three years ended December 31, 2007
  FS-30
Consolidated Statement of Stockholders’ Equity for the three years ended December 31, 2007
  FS-31
Notes to the Consolidated Financial Statements
  FS-32 to FS-58
 
              (2)  Financial Statement Schedules:
 
         We have included, on page 39, Schedule II — Valuation and Qualifying Accounts.
 
              (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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Table of Contents

 
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars
 
                         
    Year Ended December 31  
    2007     2006     2005  
 
Employee Termination Benefits:
                       
Balance at January 1
  $ 28     $ 91     $ 137  
Additions (deductions) charged (credited) to expense
    106       (21 )     (21 )
Additions related to Unocal acquisition
                106  
Payments
    (17 )     (42 )     (131 )
                         
Balance at December 31
  $ 117     $ 28     $ 91  
                         
Allowance for Doubtful Accounts:
                       
Balance at January 1
  $ 217     $ 198     $ 219  
Additions charged to expense
    29       61       3  
Additions related to Unocal acquisition
                6  
Bad debt write-offs
    (46 )     (42 )     (30 )
                         
Balance at December 31
  $ 200     $ 217     $ 198  
                         
Deferred Income Tax Valuation Allowance:*
                       
Balance at January 1
  $ 4,391     $ 3,249     $ 1,661  
Additions charged to deferred income tax expense
    1,894       1,700       1,593  
Additions related to Unocal acquisition
                400  
Deductions credited to goodwill
          (77 )     (60 )
Deductions credited to deferred income tax expense
    (336 )     (481 )     (345 )
                         
Balance at December 31
  $ 5,949     $ 4,391     $ 3,249  
                         
 
      See also Note 15 to the Consolidated Financial Statements beginning on page FS-43.
 


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SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 28th day of February, 2008.
 
Chevron Corporation
 
  By 
/s/  David J. O’Reilly
David J. O’Reilly, 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 28th day of February, 2008.
 
     
Principal Executive Officers
   
(and Directors)   Directors
 
/s/David J. O’Reilly
David J. O’Reilly, Chairman of the
Board and Chief Executive Officer
  Samuel H. Armacost*
Samuel H. Armacost
     
/s/Peter J. Robertson
Peter J. Robertson, 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
  Sam Ginn*
Sam Ginn
/s/Stephen J. Crowe
Stephen J. Crowe, Vice President and Chief Financial Officer
  Franklyn G. Jenifer*
Franklyn G. Jenifer
     
Principal Accounting Officer
   
/s/Mark A. Humphrey
Mark A. Humphrey, Vice President and Comptroller
  Sam Nunn*
Sam Nunn
     
    Donald B. Rice*
Donald B. Rice
     
*By: /s/Lydia I. Beebe
Lydia I. Beebe,
Attorney-in-Fact
  Kevin W. Sharer*
Kevin W. Sharer
    Charles R. Shoemate*
Charles R. Shoemate
     
    Ronald D. Sugar*
Ronald D. Sugar
     
    Carl Ware*
Carl Ware


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(This Page Intentionally Left Blank)
 


 

INDEX TO MANAGEMENT’S DISCUSSION AND ANALYSIS,
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

         
FS-2    
   
 
   
Management’s Discussion and Analysis of Financial Condition and Results of Operations    
Key Financial Results   FS-2
Income by Major Operating Area   FS-2
Business Environment and Outlook   FS-2
Operating Developments   FS-5
Results of Operations   FS-6
Consolidated Statement of Income   FS-9
Selected Operating Data   FS-l0
Liquidity and Capital Resources   FS-11
Financial Ratios   FS-13
Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies   FS-13
Financial and Derivative Instruments   FS-14
Transactions With Related Parties   FS-15
Litigation and Other Contingencies   FS-16
Environmental Matters   FS-18
Critical Accounting Estimates and Assumptions   FS-18
New Accounting Standards   FS-21
   
 
   
   
 
   
FS-24    
   
 
   
Consolidated Financial Statements    
Quarterly Results and Stock Market Data   FS-24
Report of Management   FS-25
Report of Independent Registered Public Accounting Firm   FS-26
Consolidated Statement of Income   FS-27
Consolidated Statement of Comprehensive Income   FS-28
Consolidated Balance Sheet   FS-29
Consolidated Statement of Cash Flows   FS-30
Consolidated Statement of Stockholders’ Equity   FS-31
   
 
   
   
 
   
FS-32    
   
 
   
Notes to the Consolidated Financial Statements    
Note 1     FS-32
Note 2     FS-34
Note 3     FS-35
Note 4     FS-35
Note 5     FS-36
Note 6     FS-36
Note 7     FS-36
Note 8     FS-37
Note 9     FS-39
Note 10     FS-40
Note 11     FS-40
Note 12     FS-42
Note 13     FS-42
Note 14     FS-43
Note 15     FS-43
Note 16     FS-45
Note 17     FS-46
Note 18     FS-46
Note 19     FS-47
Note 20     FS-48
Note 21     FS-53
Note 22     FS-55
Note 23     FS-57
Note 24     FS-58
Note 25     FS-58
Five-Year Financial Summary   FS-60
Supplemental Information on Oil and Gas Producing Activities   FS-61

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   2007       2006     2005  
       
Net Income
  $ 18,688       $ 17,138     $ 14,099  
Per Share Amounts:
                         
Net Income – Basic
  $ 8.83       $ 7.84     $ 6.58  
– Diluted
  $ 8.77       $ 7.80     $ 6.54  
Dividends
  $ 2.26       $ 2.01     $ 1.75  
Sales and Other Operating Revenues
  $ 214,091       $ 204,892     $ 193,641  
Return on:
                         
Average Capital Employed
    23.1 %       22.6 %     21.9 %
Average Stockholders’ Equity
    25.6 %       26.0 %     26.1 %
       

Income by Major Operating Area

                           
Millions of dollars   2007       2006     2005  
       
Upstream – Exploration and Production
                         
    United States
  $ 4,532       $ 4,270     $ 4,168  
    International
    10,284         8,872       7,556  
       
Total Upstream
    14,816         13,142       11,724  
       
Downstream – Refining, Marketing and Transportation
                         
    United States
    966         1,938       980  
    International
    2,536         2,035       1,786  
       
Total Downstream
    3,502         3,973       2,766  
       
Chemicals
    396         539       298  
All Other
    (26 )       (516 )     (689 )
       
Net Income*
  $ 18,688       $ 17,138     $ 14,099  
       
*Includes Foreign Currency Effects:
    $ (352)         $ (219)       $ (61)  

     Refer to the “Results of Operations” section beginning on page FS-6 for a detailed discussion of financial results by major operating area for the three years ending December 31, 2007.

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, France, India, Indonesia, Kazakhstan, Myanmar, the Netherlands, Nigeria, Norway, the Partitioned Neutral Zone between Saudi Arabia and Kuwait, the Philippines, Qatar, Republic of the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, Venezuela and Vietnam.
     Current and future 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 and/or unusual in nature.
     Chevron and the oil and gas industry at large continue to experience an increase in certain costs that exceeds the general trend of inflation in many areas of the world. This increase in costs is affecting the company’s operating expenses and capital expenditures, particularly for the upstream business. 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 adequate financial returns for the investment required. Identifying promising areas for exploration, acquiring the necessary rights to explore for and to produce crude oil and natural gas, drilling successfully, and handling the many technical and operational details in a safe and cost-effective manner are all important factors in this effort. Projects often require long lead times and large capital commitments. In the current environment of higher commodity prices, certain governments have sought to renegotiate contracts or impose additional costs on the company. Other governments may attempt to do so in the future. The company will continue to monitor these developments, take them into account in evaluating future investment opportunities, and otherwise seek to mitigate any risks to the company’s current operations or future prospects.
     The company also 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 growth. Asset sales during 2007 included the company’s 31 percent ownership interest in a refinery and related assets in the Netherlands; fuels marketing businesses in Belgium, Luxembourg, the Netherlands and Uruguay; and the investment in common stock of Dynegy Inc. Other asset dispositions and restructurings may occur in future periods and could result in significant gains or losses.
     Comments related to earnings trends for the company’s major business areas are as follows:


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     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

(LINE CHART)

may be caused by military conflicts, civil unrest or political uncertainty. Moreover, any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments, and attempts to manage risks in operating its facilities and business.

     Price levels for capital and exploratory costs and operating expenses associated with the efficient 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 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. The oil and gas industry worldwide has experienced significant price increases for these items since 2005, and future price increases may continue to exceed the general level of inflation. Capital and exploratory expenditures and operating expenses also can be affected by damages to production facilities caused by severe weather or civil unrest.
     Industry price levels for crude oil increased during 2007. The spot price for West Texas Intermediate (WTI) crude oil, a benchmark crude oil, averaged $72 per barrel in 2007, up approximately $6 per barrel from the 2006 average price. The rise in crude oil prices was attributed primarily to increasing demand in growing economies, the heightened level of geopolitical uncertainty in some areas of the world and supply concerns in other key producing regions. As of mid-February 2008, the WTI price was about $93 per barrel.
     As in 2006, a wide differential in prices existed in 2007 between high-quality (i.e., high-gravity, low sulfur) crude oils
and those of lower quality (i.e., low-gravity, heavier types of crude). The price for the heavier crudes has been dampened because of ample supply and lower relative demand due to the limited number of refineries that are able to process this lower-quality feedstock into light products (i.e., motor gasoline, jet fuel, aviation gasoline and diesel fuel). The price for higher-quality crude oil has remained high, as the demand for light products, which can be more easily manufactured by refineries from high-quality crude oil, has been strong worldwide. Chevron produces or shares in the production of heavy crude oil in California, Chad, Indonesia, the Partitioned Neutral Zone between Saudi Arabia and Kuwait, Venezuela and certain fields in Angola, China and the United Kingdom North Sea. (Refer to page FS-l0 for the company’s average U.S. and international crude oil prices.)
     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 during 2007, benchmark prices at Henry Hub averaged about $7 per thousand cubic feet (MCF), compared with about $6.50 in 2006. As of mid-February 2008, the Henry Hub price was about $8 per MCF. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage relative to customer demand. U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest.
     Certain other regions of the world in which the company operates have different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices for the company’s production of natural gas. (Refer to page FS-l0 for the company’s average natural gas prices for the U.S. and international regions.) Additionally, excess-supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-

(BAR CHARTS)



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Table of Contents

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

price conditions in the United States and other markets because of the lack of infrastructure to transport and receive liquefied natural gas.
     To help address this regional imbalance between supply and demand for natural gas, Chevron is planning increased investments in long-term projects in areas of excess supply to install infrastructure to produce and liquefy natural gas for transport by tanker, along with investments and commitments to regasify the product in markets where demand is strong and supplies are not as plentiful. Due to the significance of the overall investment in these long-term projects, the natural gas sales prices in the areas of excess supply (before the natural gas is transferred to a company-owned or third-party processing facility) are expected to remain well below sales prices for natural gas that is produced much nearer to areas of high demand and can be transported in existing natural gas pipeline networks (as in the United States).
     Besides the impact of the fluctuation in price for crude oil and natural gas, the longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, changes in tax rates on income, and the cost of goods and services.
     Chevron’s worldwide net oil-equivalent production in 2007, including volumes produced from oil sands, averaged 2.62 million barrels per day, a decline of about 48,000 barrels per day from 2006, due mainly to the effect of a conversion of operating service agreements in Venezuela to joint-stock companies. (Refer to the table “Selected Operating Data” on page FS-l0 for a listing of production volumes for each of the three years ending December 31, 2007.) The company estimates that oil-equivalent production in 2008 will average approximately 2.65 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, weather conditions that may shut in production, civil unrest, 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. Most of Chevron’s upstream investment is currently being made outside the United States. Investments in upstream projects generally are made well in advance of the start of the associated crude oil and natural gas production.
     Approximately 28 percent of the company’s net oil-equivalent production in 2007 occurred in the OPEC-member countries of Angola, Indonesia, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. OPEC quotas did not significantly affect Chevron’s production level in 2007.
The impact of OPEC quotas on the company’s production in 2008 is uncertain.
     In October 2006, Chevron’s Boscan and LL-652 operating service agreements in Venezuela were converted to Empresas Mixtas (i.e., joint-stock companies), with Petróleos de Venezuela, S.A. (PDVSA) as majority shareholder. From that time, Chevron reported its equity share of the Boscan and LL-652 production, which was approximately 85,000 barrels per day less than what the company previously reported under the operating service agreements. The change to the Empresa Mixta structure did not have a material effect on the company’s results of operations, consolidated financial position or liquidity.
     In February 2007, the president of Venezuela issued a decree announcing the government’s intention for PDVSA to take over operational control of all Orinoco Heavy Oil Associations effective May 1, 2007, and to increase its ownership in all such Associations to a minimum of 60 percent. The decree included Chevron’s 30 percent-owned Hamaca project. In April 2007, Chevron signed a memorandum of understanding (MOU) with PDVSA that summarized the ongoing discussions to transfer control of Hamaca operations in accordance with the February decree. As provided in the MOU, a PDVSA-controlled transitory operational committee, on which Chevron had representation, assumed responsibility for daily operations on May 1, 2007. The MOU stipulated that terms of existing contracts were to remain in place during the transition period. In December 2007, Chevron executed a conversion agreement and signed a charter and by-laws with a PDVSA subsidiary that provided for Chevron to retain its 30 percent interest in the Hamaca project. The new entity, Petropiar, commenced activities in January 2008. The conversion agreement did not have a material effect on Chevron’s results of operations, consolidated financial position or liquidity.
     Refer to pages FS-6 through FS-7 for additional discussion of the company’s upstream operations.

     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, refinery maintenance programs and disruptions at refineries resulting from unplanned outages that may be 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, the effectiveness of the crude-oil and


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Table of Contents

product-supply functions and the economic returns on invested capital. 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, sub-Saharan Africa and the United Kingdom. Chevron operates or has ownership interests in refineries in each of these areas except Latin America. For the industry, refined-product margins were generally higher in 2007 than in 2006. For the company, U.S. refined-product margins during 2007 were negatively affected by planned and unplanned downtime at its three largest U.S. refineries.
     Industry margins in the future may be volatile and are influenced by changes in the price of crude oil used for refinery feedstock and by changes in the supply and demand for crude oil and refined products. The industry supply and demand balance can be affected by disruptions at refineries resulting from maintenance programs and unplanned outages, including weather-related disruptions; refined-product inventory levels; and geopolitical events.
     Refer to page FS-7 through 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 page FS-8 for additional discussion of chemicals earnings.

(BAR CHART)

Operating Developments

Key operating developments and other events during 2007 and early 2008 included the following:

Upstream

Angola  Discovered crude oil at the 31 percent-owned and operated Malange-1 well in offshore Block 14. Additional drilling and geologic and engineering studies are planned to appraise the discovery. The company and partners also made the final investment decision to construct a liquefied natural gas (LNG) plant that will be owned 36 percent by Chevron. The plant will be designed


with a capacity to process 1 billion cubic feet of natural gas per day and produce 5.2 million metric tons a year of LNG and related gas liquids products.
     Australia  Received federal and state environmental approvals for development of the 50 percent-owned and operated Gorgon LNG project located off the northwest coast. The approvals represented a significant milestone towards the development of the company’s natural gas resources offshore Australia.
     Bangladesh  Began production at the 98 percent-owned Bibiyana natural gas field. The field’s total production is expected to increase to a maximum of 500 million cubic feet per day by 2010.
     China  Signed a 30-year production-sharing contract with China National Petroleum Corporation to assume operatorship and hold a 49 percent interest in the development of the Chuandongbei natural gas area in central China. Design input capacity of the proposed gas plants is expected to be 740 million cubic feet of natural gas per day.
     Indonesia  Began commercial operation of the 1l0-megawatt Darajat III geothermal power plant in Garut, West Java. The plant increased Darajat’s total capacity to 259 megawatts.
     Kazakhstan  Initiated production from the first phase of the Sour Gas Injection and Second Generation Plant expansion projects at the 50 percent-owned Tengiz Field. This phase increased production capacity by 90,000 barrels of crude oil per day to approximately 400,000. Full facility expansion is expected to occur during the second-half 2008, increasing production capacity to 540,000 barrels per day.
     Republic of the Congo  Confirmed two crude oil discoveries in the offshore Moho-Bilondo permit. Evaluation and development studies were undertaken to appraise the discoveries, in which Chevron holds a 32 percent nonoperated working interest.
     Thailand  Signed an agreement to increase sales of natural gas from company-operated Blocks 10, 11, 12 and 13 in the Gulf of Thailand to PTT Public Company Limited. Chevron has ownership interests ranging from 60 percent to 80 percent in the blocks, which received 10-year production-period extensions to 2022. The company was also granted the concession rights for a six-year period to four prospective offshore petroleum blocks, three of which it will operate.
     Trinidad and Tobago  Signed an agreement to sell natural gas to the National Gas Company of Trinidad and Tobago for 11 years with an option for a four-year extension. The gas is expected to be sourced from Chevron’s 50 percent-owned East Coast Marine Area.
     United States  Announced that first production from the Tahiti project in the deepwater Gulf of Mexico is expected by the third quarter 2009. The start-up is approximately one year later than originally planned due to metallurgical problems with the mooring shackles for the floating production facility.

Downstream

Benelux Countries  Sold the company’s 31 percent interest in the Nerefco Refinery and related assets in the Netherlands, and the company’s fuels marketing businesses in Belgium, Luxembourg and the Netherlands, resulting in gains totaling $960 million.


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Table of Contents

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

     South Korea   Completed construction and commissioned new facilities associated with a $1.5 billion upgrade at the 50 percent-owned GS Caltex Yeosu Refinery, enabling the refinery to process heavier and higher-sulfur crude oils and increase the production of gasoline, diesel and other light products.
     United States   Approved plans at the company’s refinery in Pascagoula, Mississippi, for the construction of a Continuous Catalyst Regeneration unit, which is expected to increase gasoline production by 10 percent, or 600,000 gallons per day, by mid-2010. At the refinery in El Segundo, California, modifications were completed to enable the processing of heavier crude oils into light transportation fuels and other refined products.

Other

Common Stock Dividends   Increased the company’s quarterly common stock dividend by 11.5 percent in April to $0.58 per share, marking the 20th consecutive year the company has increased its annual dividend payment.
     Common Stock Repurchase Program   Approved a program in September to acquire up to $15 billion of the company’s common stock over a period of up to three years, which followed three stock repurchase programs of $5 billion each that were completed in 2005, 2006 and September 2007.
     Dynegy   Sold the company’s common stock investment in Dynegy Inc., resulting in a gain of $680 million.

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. Income is also presented for the U.S. and international geographic areas of the upstream and downstream business segments. (Refer to Note 8, beginning on page FS-37, for a discussion of the company’s “reportable segments,” as defined in FASB No. 131, Disclosures About Segments of an Enterprise and Related Information.) 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   2007       2006     2005
       
Income
  $ 4,532       $ 4,270     $ 4,168
       

     U.S. upstream income of $4.5 billion in 2007 increased approximately $260 million from 2006. Results in 2007 benefited approximately $700 million from higher prices for crude oil and natural gas liquids. This benefit to income was partially offset by the

effects of a decline in oil-equivalent production and an increase in depreciation, operating and exploration expenses.
     Income of $4.3 billion in 2006 increased approximately $100 million from 2005. Earnings in 2006 benefited about $850 million from higher average prices on oil-equivalent production and the effect of seven additional months of production from the Unocal properties that were acquired in August 2005. Substantially offsetting these benefits were increases in operating, exploration and depreciation expenses. Included in the operating expense increases were costs associated with the carryover effects of hurricanes in the Gulf of Mexico in 2005.
     The company’s average realization for crude oil and natural gas liquids in 2007 was $63.16 per barrel, compared with $56.66 in 2006 and $46.97 in 2005. The average natural gas realization was $6.12 per thousand cubic feet in 2007, compared with $6.29 and $7.43 in 2006 and 2005, respectively.

(BAR CHARTS)

     Net oil-equivalent production in 2007 averaged 743,000 barrels per day, down 2.6 percent from 2006 and up 2 percent from 2005, which included only five months of production from the Unocal properties acquired in August of that year. The net liquids component of oil-equivalent production for 2007 averaged 460,000 barrels a day, which was essentially flat compared with 2006, and an increase of 1 percent from 2005. Net natural gas production averaged 1.7 billion cubic feet per day in 2007, down 6 percent from 2006 and up 4 percent from 2005.



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Table of Contents

     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   2007       2006     2005
       
Income*
  $ 10,284       $ 8,872     $ 7,556
       
*Includes Foreign Currency Effects:
    $ (417)         $ (371)       $ 14

     International upstream income of $10.3 billion in 2007 increased $1.4 billion from 2006. Earnings in 2007 benefited approximately $1.6 billion from higher prices, primarily for crude oil, and $300 million from increased liftings. Non-recurring income tax items also benefited earnings between periods. These benefits to income were partially offset by the impact of higher operating and depreciation expenses.

     Income in 2006 of approximately $8.9 billion increased $1.3 billion from 2005. Earnings in 2006 benefited approximately $3 billion from higher prices for crude oil and natural gas and an additional seven months of production from the former Unocal properties. About 70 percent of this benefit was associated with the impact of higher prices. Substantially offsetting these benefits were increases in depreciation expense, operating expense and exploration expense. Also adversely affecting 2006 income were higher taxes related to an increase in tax rates in the U.K. and Venezuela and settlement of tax claims and other tax items in Venezuela, Angola and Chad. Foreign currency effects reduced earnings by $371 million in 2006, but increased income $14 million in 2005.
     The company’s average realization for crude oil and natural gas liquids in 2007 was $65.01 per barrel, compared with $57.65 in 2006 and $47.59 in 2005. The average natural gas realization was $3.90 per thousand cubic feet in 2007, compared with $3.73 and $3.19 in 2006 and 2005, respectively.
     Net oil-equivalent production of 1.88 million barrels per day in 2007 declined about 2 percent from 2006 and increased 5 percent from 2005. The volumes for each year included production from oil sands in Canada and an operating service agreement in Venezuela until its conversion to a joint-stock company in October 2006. The decline between 2006 and 2007 was associated with the impact of this contract conversion in Venezuela and the price effects on production volumes calculated under production-sharing agreements. Partially offsetting the decline was increased production in Bangladesh, Angola and Azerbaijan. The increase from 2005 was due to that year having included only five months of production from the former Unocal properties.
     The net liquids component of oil-equivalent production was 1.3 million barrels per day in 2007, a decrease of approximately 4 percent from 2006 and 3 percent from 2005. Net natural gas production of 3.3 billion cubic feet per day in 2007 was up 5.5 percent and 28 percent from 2006 and 2005, respectively.
     Refer to the “Selected Operating Data” table, on page FS-10, for the three-year comparative of international production volumes.

US. Downstream - Refining, Marketing and Transportation

                         
Millions of dollars   2007       2006     2005
       
Income
  $ 966       $ 1,938     $ 980
       

     U.S. downstream earnings of $966 million in 2007 declined nearly $1 billion from 2006 and were essentially the same as 2005. The decline in 2007 from 2006 was associated mainly with weaker refined-product margins due to the effects of higher crude oil prices and the negative impacts of higher planned and unplanned downtime on refinery production volumes at the company’s three major refineries. Operating expenses were also higher in 2007. The improvement in 2006 earnings from 2005 was primarily associated with higher average refined-product margins in 2006 and the adverse effect of downtime in 2005 at refining, marketing and pipeline operations that was caused by hurricanes in the Gulf of Mexico.

     Sales volumes of refined products were 1.46 million barrels per day in 2007, a decrease of 3 percent and 1 percent from 2006 and 2005, respectively. The reported sales volume for 2007 was on a different basis than 2006 and 2005 due to a change in accounting rules that became effective April 1, 2006, for certain purchase and sale (buy/sell) contracts with the same counterparty. Excluding the impact of this accounting standard, refined-product sales in 2007 decreased 1 percent from 2006 and increased about 5 percent from 2005. Branded gasoline sales volumes of 629,000 barrels per day in 2007 increased about 2 percent from 2006 and 6 percent from 2005, largely due to growth of the Texaco brand.
     Refer to the “Selected Operating Data” table on page FS-l0 for a three-year comparative of sales volumes of gasoline and other refined products and refinery-input volumes. Refer also to Note 13, “Accounting for Buy/Sell Contracts,” on page FS-42 for a discussion of the accounting for purchase and sale contracts with the same counterparty.

(BAR CHARTS)



FS-7


Table of Contents

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

International Downstream Refining, Marketing and Transportation

                         
Millions of dollars   2007       2006     2005
       
Income*
  $ 2,536       $ 2,035     $ 1,786
       
*Includes Foreign Currency Effects:
    $ 62         $ 98       $(24 )

     International downstream income of $2.5 billion in 2007 increased about $500 million from 2006 and $750 million from 2005. Results for 2007 included gains of approximately $1 billion on the sale of assets, including an interest in a refinery and marketing (BAR CHART) assets in the Benelux region of Europe. Margins on the sale of refined products in 2007 were up slightly from the prior year. Operating expenses were higher, and earnings from the company’s shipping operations were lower. The increase in earnings in 2006 compared with 2005 was associated mainly with the benefit of higher refined-product sales margins in the Asia-Pacific area and Canada and improved results from crude-oil and refined-product trading activities.

     Refined-product sales volumes were 2.03 million barrels per day in 2007, about 5 percent and 10 percent lower than 2006 and 2005, respectively, due largely to the impact of asset sales and the accounting-standard change for buy/sell contracts. Excluding the accounting change, sales decreased about 4 percent and 5 percent from 2006 and 2005, respectively.
     Refer to the “Selected Operating Data” table on page FS-10 for a three-year comparative of sales volumes of gasoline and other refined products and refinery-input volumes. Refer also to Note 13, “Accounting for Buy/Sell Contracts,” on page FS-42 for a discussion of the accounting for purchase and sale contracts with the same counterparty.

Chemicals

                         
Millions of dollars   2007       2006     2005
       
Income*
  $ 396       $ 539     $ 298
       
*Includes Foreign Currency Effects:
    $ (3)         $ (8)       $ –

     The chemicals segment includes the company’s Oronite subsidiary and the 50 percent-owned Chevron Phillips Chemical (BAR CHART) Company LLC (CPChem). In 2007, earnings were $396 million, compared with $539 million and $298 million in 2006 and 2005, respectively. Between 2006 and 2007, the benefit of improved margins on sales of lubricants and fuel additives by Oronite was more than offset by the effect of lower margins on the sale of commodity chemicals by CPChem. In 2006, earnings of $539 million increased about $240 million from 2005 due to higher margins for commodity chemicals at CPChem and for fuel and lubricant additives at Oronite.
 
 
 

All Other

                           
Millions of dollars   2007       2006     2005
       
Net Charges*
  $ (26 )     $ (516 )   $ (689 )
       
*Includes Foreign Currency Effects:
    $ 6         $ 62       (51 )

     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 prior to its sale in May 2007.

     Net charges of $26 million in 2007 decreased $490 million from 2006. 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. Excluding these items and the effects of foreign currency, net charges decreased about $40 million between periods.
     Net charges of $516 million in 2006 decreased $173 million from $689 million in 2005. Excluding the effects of foreign currency, net charges declined $60 million between periods, primarily due to higher interest income and lower interest expense in 2006.


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Table of Contents

Consolidated Statement of Income

Comparative amounts for certain income statement categories are shown below:
                           
Millions of dollars   2007       2006     2005  
         
Sales and other operating revenues
  $ 214,091       $ 204,892     $ 193,641  
         

     Sales and other operating revenues in 2007 increased over 2006 due primarily to higher prices for crude oil, natural gas, natural gas liquids and refined products, partially offset by lower sales volumes. The increase in 2006 from 2005 was primarily due to higher prices for refined products. The higher revenues in 2006 were net of an impact from a change in the accounting for buy/sell contracts, as described in Note 13 on page FS-42.

                           
Millions of dollars   2007       2006     2005  
         
Income from equity affiliates
  $ 4,144       $ 4,255     $ 3,731  
         

     Lower income from equity affiliates in 2007 was mainly due to a decline in earnings from CPChem, Dynegy (sold in May 2007) and downstream affiliates in the Asia-Pacific area. Partially offsetting these declines were improved results for Tengizchevroil (TCO) and income for a full year from Petroboscan, which was converted from an operating service agreement to a joint-stock company in October 2006. The increase between 2005 and 2006 was primarily due to improved results for TCO and CPChem. Refer to Note 11, beginning on page FS-40, for a discussion of Chevron’s investment in affiliated companies.

                           
Millions of dollars   2007       2006     2005  
         
Other income
  $ 2,669       $ 971     $ 828  
         

     Other income of nearly $2.7 billion in 2007 included the net of gains totaling $1.7 billion from the sale of downstream assets in the Benelux countries and the company’s investment in Dynegy and a loss of approximately $245 million on the early redemption of Texaco debt. Interest income was approximately $600 million, $600 million and $400 million in 2007, 2006 and 2005, respectively. Foreign currency losses were $352 million, $260 million and $60 million in the corresponding years.

                           
Millions of dollars   2007       2006     2005  
         
Purchased crude oil and products
  $ 133,309       $ 128,151     $ 127,968  
         

     Crude oil and product purchases in 2007 increased from 2006 due to higher prices for crude oil, natural gas, natural gas liquids and refined products. Crude oil and product purchases in 2006 increased from 2005 on higher prices for crude oil and refined products and the inclusion of Unocal-related amounts for the full year 2006 vs. five months in 2005. The increase was mitigated by the effect of the accounting change in April 2006 for buy/sell contracts.

                           
Millions of dollars   2007       2006     2005  
         
Operating, selling, general and administrative expenses
  $ 22,858       $ 19,717     $ 17,019  
         

     Operating, selling, general and administrative expenses in 2007 increased 16 percent from a year earlier. Expenses were higher in a number of categories, with the largest increases recorded for the cost of employee payroll and contract labor. Total expenses increased in 2006 from 2005 due mainly to the inclusion of former-Unocal expenses for the full year 2006. Besides this effect, expenses were higher in 2006 for labor, transportation, and uninsured costs associated with the hurricanes in 2005.

                           
Millions of dollars   2007       2006     2005  
         
Exploration expense
  $ 1,323       $ 1,364     $ 743  
         

     Exploration expenses in 2007 declined from 2006 mainly due to lower amounts for well write-offs and geological and geophysical costs for operations outside the United States. Expenses increased in 2006 from 2005 due to higher amounts for well write-offs and geological and geophysical costs for operations outside the United States, as well as the inclusion of Unocal-related amounts for the full year 2006.

                           
Millions of dollars   2007       2006     2005  
         
Depreciation, depletion and amortization
  $ 8,708       $ 7,506     $ 5,913  
         

     Depreciation, depletion and amortization expenses increased from 2005 through 2007, reflecting an increase in charges related to asset write-downs and higher depreciation rates for certain crude oil and natural gas producing fields worldwide and the inclusion of Unocal-related amounts beginning in August 2005.

                           
Millions of dollars   2007       2006     2005  
         
Taxes other than on income
  $ 22,266       $ 20,883     $ 20,782  
         

     Taxes other than on income increased in 2007 from a year earlier due to higher duties in the company’s U.K. downstream operations. Taxes other than on income were essentially unchanged in 2006 from 2005, with the effect of higher U.S. refined product sales being offset by lower sales volumes subject to duties in the company’s European downstream operations.

                           
Millions of dollars   2007       2006     2005  
         
Interest and debt expense
  $ 166       $ 451     $ 482  
         

     Interest and debt expense in 2007 decreased from 2006 primarily due to lower average debt balances and higher amounts of interest capitalized. The decrease in 2006 vs. 2005 was mainly due to lower average debt balances and an increase in the amount of interest capitalized, partially offset by higher average interest rates on commercial paper and other variable-rate debt.



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Table of Contents

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

                           
Millions of dollars   2007       2006     2005  
         
Income tax expense
  $ 13,479       $ 14,838     $ 11,098  
         

     Effective income tax rates were 42 percent in 2007, 46 percent in 2006 and 44 percent in 2005. Rates were lower in 2007 compared with the prior year due mainly to the impact of nonrecurring items, including asset sales in 2007 and the absence of 2006 charges related to a tax-law change that increased tax rates on upstream operations in the U.K. North Sea and the settlement of a tax claim in Venezuela. The higher tax rate in 2006 compared with 2005 also reflected these nonrecurring charges in 2006. Refer also to the discussion of income taxes in Note 15 beginning on page FS-43.

Selected Operating Data1,2

                           
    2007       2006     2005  
         
U.S. Upstream3
                         
Net Crude Oil and Natural Gas Liquids Production (MBPD)
    460         462       455  
Net Natural Gas Production (MMCFPD)4
    1,699         1,810       1,634  
Net Oil-Equivalent Production (MBOEPD)
    743         763       727  
Sales of Natural Gas (MMCFPD)
    7,624         7,051       5,449  
Sales of Natural Gas Liquids (MBPD)
    160         124       151  
Revenues From Net Production
                         
Liquids ($/Bbl)
  $ 63.16       $ 56.66     $ 46.97  
Natural Gas ($/MCF)
  $ 6.12       $ 6.29     $ 7.43  
                           
International Upstream3
                         
Net Crude Oil and Natural Gas Liquids Production (MBPD)
    1,296         1,270       1,214  
Net Natural Gas Production (MMCFPD)4
    3,320         3,146       2,599  
Net Oil-Equivalent Production (MBOEPD)5
    1,876         1,904       1,790  
Sales Natural Gas (MMCFPD)
    3,792         3,478       2,450  
Sales Natural Gas Liquids (MBPD)
    118         102       120  
Revenues From Liftings
                         
Liquids ($/Bbl)
  $ 65.01       $ 57.65     $ 47.59  
Natural Gas ($/MCF)
  $ 3.90       $ 3.73     $ 3.19  
                           
U.S. and International Upstream3
                         
Net Oil-Equivalent Production Including Other Produced Volumes (MBOEPD)4,5
                         
United States
    743         763       727  
International
    1,876         1,904       1,790  
             
Total
    2,619         2,667       2,517  
                           
U.S. Downstream
                         
Gasoline Sales (MBPD)6
    728         712       709  
Other Refined Product Sales (MBPD)
    729         782       764  
             
Total (MBPD)7
    1,457         1,494       1,473  
Refinery Input (MBPD)
    812         939       845  
                           
International Downstream
                         
Gasoline Sales (MBPD)6
    581         595       662  
Other Refined Product Sales (MBPD)
    1,446         1,532       1,590  
             
Total (MBPD)7,8
    2,027         2,127       2,252  
Refinery Input (MBPD)
    1,021         1,050       1,038  
         
                         
1 Includes equity in 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 gas = 1 barrel of oil.
3 Includes net production beginning August 2005, for properties associated with acquisition
   of Unocal.
4 Includes natural gas consumed in operations (MMCFPD):
          United States
    65       56       48  
          International
    433       419       356  
5 Includes other produced volumes (MBPD):
          Athabasca Oil Sands – Net
    27       27       32  
          Boscan Operating Service Agreement
          82       111  
       
 
    27       109       143  
6 Includes branded and unbranded gasoline.
7 Includes volumes for buy/sell contracts (MBPD):
          United States
          26       88  
          International
          24       129  
8 Includes sales of affiliates (MBPD):
    492       492       498  


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Table of Contents

Liquidity and Capital Resources

Cash, cash equivalents and marketable securities  Total balances were $8.1 billion and $11.4 billion at December 31, 2007 and 2006, respectively. Cash provided by operating activities in 2007 was $25.0 billion, compared with $24.3 billion in 2006 and $20.1 billion in 2005.
     Cash provided by operating activities was net of contributions to employee pension plans of $300 million, $400 million and $1.0 billion in 2007, 2006 and 2005, respectively. Cash provided by investing activities included proceeds from asset sales of $3.3 billion in 2007, $1.0 billion in 2006 and $2.7 billion in 2005.
     Cash provided by operating activities and asset sales during 2007 was sufficient to fund the company’s $17.7 billion capital and exploratory program, pay $4.8 billion of dividends to stockholders and repay approximately $3.7 billion of debt.
     Restricted cash of $799 million associated with capital-investment projects at the company’s Pascagoula, Mississippi, refinery and Angola liquefied natural gas project was invested in short-term marketable securities and reclassified from cash equivalents to a long-term asset on the Consolidated Balance Sheet.
     Dividends  The company paid dividends of approximately $4.8 billion in 2007, $4.4 billion in 2006 and $3.8 billion in 2005. In April 2007, the company increased its quarterly common stock dividend by 11.5 percent to 58 cents per share.
     Debt, capital lease and minority interest obligations  Total debt and capital lease balances were $7.2 billion at December 31, 2007, down from $9.8 billion at year-end 2006. The company also had minority interest obligations of $204 million, down from $209 million at December 31, 2006.
     The $2.6 billion reduction in total debt and capital lease obligations during 2007 included the early redemption and maturity of individual debt issues. In February, $144 million of Texaco Capital Inc. bonds matured. In the second and fourth quarters, the company redeemed approximately $809 million and $65 million, respectively of Texaco Capital Inc.

(BAR GRAPHS)

debt and recognized an after-tax loss of approximately $175 million. In August, $2 billion of Chevron Canada Funding Company bonds matured. In December, the company issued a $650 million tax exempt Mississippi Gulf Opportunity Zone bond to fund an upgrade project at the company’s refinery in Pascagoula, Mississippi. Commercial paper balances at the end of 2007 declined approximately $450 million from $3.5 billion at year-end 2006. In February 2008, $750 million of Chevron Canada Funding Company bonds matured.
     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 $5.5 billion at December 31, 2007, down from $6.6 billion at year-end 2006. Of these amounts, $4.4 billion and $4.5 billion were reclassified to long-term at the end of each period, respectively. At year-end 2007, settlement of these obligations was not expected to require the use of working capital within one year, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.
     At year-end 2007, the company had $5 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, 2007.
     In March 2007, the company filed with the Securities and Exchange Commission (SEC) an automatic registration statement that expires in March 2010. This registration statement is for an unspecified amount of non-convertible debt securities issued or guaranteed by the company. At the same time, the company withdrew three shelf registration statements on file with the SEC that permitted the issuance of up to $3.8 billion of debt securities.
     At December 31, 2007, the company had outstanding public bonds issued by Chevron Corporation Profit Sharing/Savings Plan Trust Fund, Chevron Canada Funding Company (formerly ChevronTexaco Capital Company), Texaco Capital Inc. and Union Oil Company of California. All of these securities are guaranteed by Chevron Corporation and are rated AA by Standard and Poor’s Corporation and Aal by Moody’s Investors Service. The rating by Moody’s reflects an upgrade in December from Aa2. The company’s U.S. commercial paper is rated A-l+ 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


FS-11


Table of Contents

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

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   A $5 billion stock repurchase program initiated in December 2006 was completed in September 2007. During 2007, about 61.5 million common shares were acquired under this program at a total cost of $4.9 billion. Upon completion of this program, the company authorized the acquisition of up to $15 billion of additional common shares from time to time 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 and may be discontinued at any time. As of December 31, 2007, 23.5 million shares had been acquired under the new program for $2.1 billion. Purchases through mid-February 2008 increased the total shares acquired to 34.2 million at a cost of approximately $3.0 billion.
     Capital and exploratory expenditures   Total reported expenditures for 2007 were $20 billion, including $2.3 billion for the company’s share of affiliates’ expenditures, which did not require cash outlays by the company. In 2006 and 2005, expenditures were $16.6 billion and $11.1 billion, respectively, including the company’s share of affiliates’ expenditures of $1.9 billion and $1.7 billion in the corresponding periods. The 2005 amount excludes $17.3 billion for the acquisition of Unocal Corporation.
     Of the $20 billion in expenditures for 2007, about three-fourths, or $15.5 billion, related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2006 and 2005. International upstream accounted for about 70 percent of the worldwide upstream investment in each of the three years, reflecting the company’s continuing focus on opportunities that are available outside the United States.
     In 2008, the company estimates capital and exploratory expenditures will be 15 percent higher at $22.9 billion, including $2.6 billion of spending by affiliates. About three-fourths of the total, or $17.5 billion, is budgeted for exploration and production activities, with $12.7 billion of this amount outside the United States. Spending in 2008 is primarily targeted for exploratory prospects in the deepwater Gulf of Mexico and western Africa and major development projects in Angola, Australia, Brazil, Indonesia, Kazakhstan, Nigeria, Thailand, the deepwater Gulf of Mexico, the Piceance Basin in Colorado and an oil sands project in Canada.
     Worldwide downstream spending in 2008 is estimated at $4.1 billion, with about $2.3 billion for projects in the United States. Capital projects include upgrades to 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 2008 are budgeted at $1.3 billion. Technology investments include projects related to unconventional hydrocarbons technologies, oil and gas reservoir management and gas-fired and renewable power generation.

(BAR GRAPHS)




Capital and Exploratory Expenditures

                                                                             
    2007       2006       2005  
Millions of dollars   U.S.     Int'l.     Total       U.S.     Int'l.     Total       U.S.     Int'l.     Total  
               
Upstream – Exploration and Production
  $ 4,558     $ 10,980     $ 15,538       $ 4,123     $ 8,696     $ 12,819       $ 2,450     $ 5,939     $ 8,389  
Downstream – Refining, Marketing and Transportation
    1,576       1,867       3,443         1,176       1,999       3,175         818       1,332       2,150  
Chemicals
    218       53       271         146       54       200         108       43       151  
All Other
    768       6       774         403       14       417         329       44       373  
               
Total
  $ 7,120     $ 12,906     $ 20,026       $ 5,848     $ 10,763     $ 16,611       $ 3,705     $ 7,358     $ 11,063  
               
Total, Excluding Equity in Affiliates
  $ 6,900     $ 10,790     $ 17,690       $ 5,642     $ 9,050     $ 14,692       $ 3,522     $ 5,860     $ 9,382  
               

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Table of Contents

     Pension Obligations   In 2007, the company’s pension plan contributions were $317 million (approximately $78 million to the U.S. plans). The company estimates contributions in 2008 will be approximately $500 million. Actual contribution amounts are dependent upon plan-investment results, changes in pension obligations, regulatory requirements and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations. 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  
    2007       2006     2005  
         
Current Ratio
    1.2         1.3       1.4  
Interest Coverage Ratio
    69.2         53.5       47.5  
Total Debt/Total Debt-Plus-Equity
    8.6 %       12.5 %     17.0 %
         

     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 2007, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $7 billion.

(BAR CHART)

     Interest Coverage Ratio – income before income tax expense, plus interest and debt expense and amortization of capitalized interest, divided by before-tax interest costs. The company’s interest coverage ratio was higher between 2007 and 2006 and between 2006 and 2005, primarily due to higher before-tax income and lower average debt balances in each of the subsequent years.
     Debt Ratio – total debt as a percentage of total debt plus equity. The progressive decrease between 2005 and 2007, was due to lower average debt levels and higher stockholders’ equity balances.


Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies

Direct Guarantee

                                         
Millions of dollars   Commitment Expiration by Period  
    Total     2008     2009-
2011
    2012     After
2012
 
   
Guarantee of non-consolidated affiliate or joint-venture obligation
  $ 613     $     $     $ 38     $ 575  
   

     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 reduce 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 carries 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 2007, 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 originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the period of Texaco’s ownership interest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims must be asserted no later than February 2009 for Equilon indemnities and no later than February 2012 for Motiva indemnities. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments. The company has not recorded any liabilities for possible claims under these indemnities. The company posts no assets as collateral and has made no payments under the indemnities.
     The amounts payable for the indemnities described above are to be net of amounts recovered from insurance carriers and others and net of liabilities recorded by Equilon or Motiva prior to September 30, 2001, for any applicable incident.
     In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. Under the indemnification agreement, the company’s liability is unlimited until April 2022, when the indemnification expires. The acquirer shares in certain environmental remediation costs up to a maximum


FS-13


Table of Contents

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

obligation of $200 million, which had not been reached as of December 31, 2007.
     Securitization  During 2007, the company completed the sale of its U.S. proprietary consumer credit card business and related receivables. This transaction included terminating the qualifying Special Purpose Entity (SPE) that was used to securitize associated retail accounts receivable.
     Through the use of another qualifying SPE, the company had $675 million of securitized trade accounts receivable related to its downstream business as of December 31, 2007. This arrangement has the effect of accelerating Chevron’s collection of the securitized amounts. Chevron’s total estimated financial exposure under this securitization at December 31, 2007, was $65 million. In the event that the SPE experiences major defaults in the collection of receivables, Chevron believes that it would have no additional loss exposure connected with third-party investments in this securitization.
     Minority Interests  The company has commitments of $204 million related to minority interests in subsidiary companies.
     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: 2008 – $4.7 billion; 2009 – $3.3 billion; 2010 – $3.3 billion; 2011 – $1.9 billion; 2012 – $1.3 billion; 2013 and after – $4.9 billion. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $3.7 billion in 2007, $3.0 billion in 2006 and $2.1 billion in 2005.
     The following table summarizes the company’s significant contractual obligations:

Contractual Obligations

                                         
Millions of dollars   Payments Due by Period  
                    2009-             After  
    Total     2008     2011     2012     2012  
   
On Balance Sheet:1
                                       
Short-Term Debt2
  $ 1,162     $ 1,162     $     $     $  
Long-Term Debt2
    5,664             4,926       33       705  
Noncancelable Capital Lease Obligations
    406             193       61       152  
Interest
    3,950       360       899       292       2,399  
Off-Balance-Sheet:
                                       
Noncancelable Operating Lease Obligations
    3,167       513       1,255       293       1,106  
Throughput and Take-or-Pay Agreements
    13,118       3,699       4,783       618       4,018  
Other Unconditional Purchase Obligations3
    6,300       988       3,779       653       880  
   
1   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 due. 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.
 
2   $4.4. 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 2009-2011 period.
 
3   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 liquefied natural gas and related natural gas liquids per year. Volumes and prices associated with these purchase obligations are neither fixed nor determinable.

Financial and Derivative Instruments

No material change in market risk occurred between 2006 and 2007 for the financial and derivative instruments discussed below. The hypothetical variances used in this section were selected for illustrative purposes only and do not represent the company’s estimation of 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 1, Item 1A, of the company’s 2007 Annual Report on Form 10-K.
Commodity Derivative 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 this activity were not material to the company’s financial position, net income or cash flows in 2007.


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Table of Contents

     The company’s market exposure positions are monitored and managed on a daily basis by an internal Risk Control group to ensure compliance with the company’s risk management policies that have been approved by the Audit Committee of the company’s Board of Directors.
     The derivative instruments used in the company’s risk management and trading activities consist mainly of futures, options, and swap contracts traded on the NYMEX (New York Mercantile Exchange) and on electronic platforms of ICE (Inter-Continental Exchange) and GLOBEX (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.
     Effective with 2007 year-end reporting, the company changed the model used to quantify information about market risk for its commodity derivatives from a “sensitivity analysis” approach to Value-at-Risk (VaR). The major reason for the change is that VaR allows estimation of a portfolio’s aggregate market risk exposure and takes into account correlations between trading assets. Therefore, it reflects risk reduction due to diversification or hedging activities. Most of the company’s market positions are time and commodity spreads, and the company believes that VaR is a more accurate tool to measure this type of exposure than the sensitivity analysis model. The company fully developed and tested its VaR model during 2007.
     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 potential portfolio’s values.
     The VaR model utilizes an exponentially-weighted moving average for computing historical volatilities and correlations, a 95 percent confidence level, and one-day holding period. That is, the company’s 95 percent, one-day VaR corresponds to the unrealized loss in portfolio value that would not be exceeded on average more than one in every 20 trading days, if the portfolio were held constant for one day.
     The one-day holding period is based on the assumption that market-risk positions can be liquidated or hedged within one day. For hedging and risk management, the company uses conventional exchange-traded instruments such as futures and options, as well as non-exchange-traded swaps, most of which can be liquidated or hedged effectively within one day. The table below presents 95 percent/one-day VaR for each of the company’s primary risk exposures in the area of commodity derivative instruments at December 31, 2007:
         
Millions of dollars   2007  
 
Crude Oil
  $ 29  
Natural Gas
    3  
Refined Products
    23  
 
     Sensitivity analysis for the company’s open commodity derivative instruments at December 31, 2007, and December 31, 2006, based on a hypothetical 10 percent increase in commodity prices, is provided in the following table:

Incremental Increase (Decrease) in Fair Value of Open Commodity
Derivative Contracts Assuming a Hypothetical Increase in
Year-End Commodity Prices of 10 Percent

                   
Millions of dollars   2007       2006  
       
Crude Oil
  $ (113 )     $ 4  
Natural Gas
    14         10  
Refined Products
    (96 )       (30 )
       

     The same hypothetical decrease in prices of these commodities would result in approximately the same opposite effects on the fair values of the contracts. The hypothetical effect on these contracts was estimated by calculating the fair value of the contracts as the difference between the hypothetical and current market prices multiplied by the contract amounts.

     The change in the amounts between years in the table above for crude oil and refined products is associated with an increase in commodity prices, volumes hedged and the use of longer-term contracts.
     Foreign Currency  The company enters into forward exchange contracts, generally with terms of 180 days or less, to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments, forecasted to occur within 180 days. The forward exchange contracts are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.
     The aggregate effect of a hypothetical 10 percent increase in the value of the U.S. dollar at year-end 2007 would be a reduction in the fair value of the foreign exchange contracts of approximately $75 million. The effect would be the opposite for a hypothetical 10 percent decrease in the value of the U.S. dollar at year-end 2007.
     Interest Rates  The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements are 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 are accounted for as fair value hedges. Interest rate swaps related to floating-rate debt are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2007, the company had no interest-rate swaps on floating-rate debt. At year-end 2007, the weighted average maturity of “receive fixed” interest rate swaps was less than one year. A hypothetical increase or decrease of 10 basis points in fixed interest rates would have a de minimis impact on the fair value of the “receive fixed” swaps.

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. Long-term purchase agreements are in place with the company’s refining affiliate


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

in Thailand. Refer to page FS-5 for further discussion. Management believes the foregoing agreements and others 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. The company is a party to 88 lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners, related to the use of MTBE in certain oxygenated gasolines and the alleged seepages of MTBE into groundwater. Chevron has agreed in principle to a tentative settlement of 60 pending lawsuits and claims. The terms of this agreement, which must be approved by a number of parties, including the court, are confidential and not material to the company’s results of operations, liquidity or financial position.
     Resolution of remaining 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 tentative settlement of the referenced 60 lawsuits did not set any precedents related to standards of liability to be used to judge the merits of the claims, corrective measures required or monetary damages to be assessed for the remaining lawsuits and claims or future lawsuits and claims. As a result, the company’s ultimate exposure related to pending lawsuits and claims is not currently 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.
     RFG Patent  Fourteen purported class actions were brought by consumers of reformulated gasoline (RFG) alleging that Unocal misled the California Air Resources Board into adopting standards for composition of RFG that overlapped with Unocal’s undisclosed and pending patents. Eleven lawsuits were consolidated in U.S. District Court for the Central District of California, where a class action has been certified, and three were consolidated in a state court action. Unocal is alleged to have monopolized, conspired and engaged in unfair methods of competition, resulting in injury to consumers of RFG. Plaintiffs in both consolidated actions seek unspecified actual and punitive damages, attorneys’ fees, and interest on behalf of an alleged class of consumers who
purchased “summertime” RFG in California from January 1995 through August 2005. The parties have reached a tentative agreement to resolve all of the above matters in an amount that is not material to the company’s results of operations, liquidity or financial position. The terms of this agreement are confidential, and subject to further negotiation and approval, including by the courts.
     Environmental  The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of 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
(BAR GRAPH)

be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemical companies.


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     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   2007       2006     2005  
       
Balance at January 1
  $ 1,441       $ 1,469     $ 1,047  
Net Additions
    562         366       731  
Expenditures
    (464 )       (394 )     (309 )
       
Balance at December 31
  $ 1,539       $ 1,441     $ 1,469  
       

     Included in the $1,539 million year-end 2007 reserve balance were remediation activities of 240 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 2007 was $123 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 consolidated financial position or liquidity.

     Of the remaining year-end 2007 environmental reserves balance of $1,416 million, $864 million related to approximately 2,000 sites for the company’s U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals) and pipelines. The remaining $552 million was associated with various sites in international downstream ($146 million), upstream ($267 million), chemicals ($105 million) and other ($34 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 or local regulations. No single remediation site at year-end 2007 had a recorded liability that was material to the company’s financial position, results of operations 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.
     The company accounts for asset retirement obligations in accordance with Financial Accounting Standards Board Statement (FASB) No. 143, Accounting for Asset Retirement Obligations (FAS 143). Under FAS 143, 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 $8.3 billion for asset retirement obligations at year-end 2007 related primarily to upstream and mining 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, beginning on page FS-57, related to FAS 143 and the company’s adoption in 2005 of FASB Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement Obligations An Interpretation of FASB Statement No. 143 (FIN 47), 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-43 for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return. 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, 2007, the company had approximately $1.7 billion of suspended exploratory wells included in properties, plant and equipment, an increase of $421 million from 2006 and an increase of $551 million from 2005.
     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 $1.7 billion of suspended wells at year-end 2007 is uncertain pending future activities, including normal project evaluation and additional drilling.
     Refer to Note 19, beginning on page FS-47, for additional discussion of suspended wells.


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

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

Environmental Matters

     Virtually all aspects of the businesses in which the company engages are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. Most of the costs of complying with laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business.
     Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In addition to the costs for environmental protection associated with its ongoing operations and products, the company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste-disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-Chevron sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative or remedial work or both to meet current standards.
     Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2007 at approximately $2.7 billion for its consolidated companies. Included in these expenditures were approximately $900 million of environmental capital expenditures and $1.8 billion of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites and the abandonment and restoration of sites.
     For 2008, total worldwide environmental capital expenditures are estimated at $1.9 billion. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.
     It is not possible to predict with certainty the amount of additional investments in new or existing facilities or amounts of incremental operating costs to be incurred in the future to: prevent, control, reduce or eliminate releases of hazardous materials into the environment; comply with existing and new environmental laws or regulations; or remediate and restore areas damaged by prior releases of hazardous materials. Although these costs may be significant to the results of operations in any single period, the company does not expect them to have a material effect on the company’s liquidity or financial position.

Critical Accounting Estimates and Assumptions

     Management makes many estimates and assumptions in the application of generally accepted accounting principles (GAAP) that may have a material impact on the company’s consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.
     The discussion in this section of “critical” accounting estimates or assumptions is according to the disclosure guidelines of the Securities and Exchange Commission (SEC), wherein:
  1.   the nature of the estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and
  2.   the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.


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     Besides those meeting these “critical” criteria, the company makes many other accounting estimates and assumptions in preparing its financial statements and related disclosures. Although not associated with “highly uncertain matters,” these estimates and assumptions are also subject to revision as circumstances warrant, and materially different results may sometimes occur.
     For example, the recording of deferred tax assets requires an assessment under the accounting rules that the future realization of the associated tax benefits be “more likely than not.” Another example is the estimation of crude oil and natural gas reserves under SEC rules that require “... geological and engineering data (that) demonstrate with reasonable certainty (reserves) to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.” Refer to Table V, “Reserve Quantity Information,” beginning on page FS-66, for the changes in these estimates for the three years ending December 31, 2007, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on page FS-74 for estimates of proved-reserve values for each of the three years ending December 31, 2007, which were based on year-end prices at the time. Note 1 to the Consolidated Financial Statements, beginning on page FS-32, includes a description of the “successful efforts” method of accounting for oil and gas exploration and production activities. The estimates of crude oil and natural gas reserves are important to the timing of expense recognition for costs incurred.
     The discussion of the critical accounting policy for “Impairment of Properties, Plant and Equipment and Investments in Affiliates,” beginning on page FS-20, includes reference to conditions under which downward revisions of proved-reserve quantities could result in impairments of oil and gas properties. This commentary should be read in conjunction with disclosures elsewhere in this discussion and in the Notes to the Consolidated Financial Statements related to estimates, uncertainties, contingencies and new accounting standards. Significant accounting policies are discussed in Note 1 to the Consolidated Financial Statements, beginning on page FS-32. The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of Directors.
     The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows:
     Pension and Other Postretirement Benefit Plans  The determination of pension plan obligations and expense is based on a number of actuarial assumptions. Two critical assumptions are the expected long-term rate of return on plan assets and the discount rate applied to pension plan obligations. For other postretirement benefit (OPEB) plans, which provide for certain health care and life insurance benefits for qualifying retired employees and which are not funded, critical assumptions in determining OPEB obligations and expense are the discount rate and the assumed health care cost-trend rates.
     Note 20, beginning on page FS-48, includes information on the funded status of the company’s pension and OPEB
plans at the end of 2007 and 2006, the components of pension and OPEB expense for the three years ending December 31, 2007, and the underlying assumptions for those periods.
     Pension and OPEB expense is recorded on the Consolidated Statement of Income in “Operating expenses” or “Selling, general and administrative expenses” and applies to all business segments. The year-end 2007 and 2006 funded status, measured as the difference between plan assets and obligations, of each of the company’s pension and OPEB plans is recognized on the Consolidated Balance Sheet. The funded status of overfunded pension plans is recorded as a long-term asset in “Deferred charges and other assets.” The funded status of underfunded or unfunded pension and OPEB plans is recorded in “Accrued liabilities” or “Reserves for employee benefit plans.” Amounts yet to be recognized as components of pension or OPEB expense are recorded in “Accumulated other comprehensive income.”
     To estimate the long-term rate of return on pension assets, the company uses a process that incorporates actual historical asset-class returns and an assessment of expected future performance and takes into consideration external actuarial advice and asset-class factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the determination of the company’s estimates of long-term rates of return are consistent with these studies. The expected long-term rate of return on U.S. pension plan assets, which account for 67 percent of the company’s pension plan assets, has remained at 7.8 percent since 2002. For the 10 years ending December 31, 2007, actual asset returns averaged 8.7 percent for this plan.
     The year-end market-related value of assets of the major U.S. pension plan used in the determination of pension expense was based on the market value in the preceding three months, as opposed to the maximum allowable period of five years under U.S. accounting rules. Management considers the three-month period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, market value of assets as of the measurement date is used in calculating the pension expense.
     The discount rate assumptions used to determine U.S. and international pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality fixed-income debt instruments. At December 31, 2007, the company selected a 6.3 percent discount rate for the major U.S. pension and postretirement plans. This rate was selected based on a cash flow analysis that matched estimated future benefit payments to the Citigroup Pension Discount Yield Curve as of year-end 2007. The discount rates at the end of 2006 and 2005 were 5.8 percent and 5.5 percent, respectively.
     An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa. Total pension expense for 2007 was $620 million. As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1 percent increase in the expected rate of return on assets of the company’s primary U.S. pension plan would have reduced total pension plan expense for 2007 by approximately $70


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

million. A 1 percent increase in the discount rate for this same plan, which accounted for about 60 percent of the companywide pension obligation, would have reduced total pension plan expense for 2007 by approximately $155 million.
     An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan recorded on the Consolidated Balance Sheet. The total pension liability on the Consolidated Balance Sheet at December 31, 2007, for underfunded plans was approximately $1.7 billion. As an indication of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent increase in the discount rate applied to the company’s primary U.S. pension plan would have reduced the plan obligation by approximately $250 million, which would have increased the plan’s over-funded status from approximately $160 million to $410 million. Other plans would be less underfunded as discount rates increase. The actual rates of return on plan assets and discount rates may vary significantly from estimates because of unanticipated changes in the world’s financial markets.
     In 2007, the company’s pension plan contributions were $317 million (including $78 million to the U.S. plans). In 2008, the company estimates contributions will be approximately $500 million. Actual contribution amounts are dependent upon plan-investment results, changes in pension obligations, regulatory requirements and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations.
     For the company’s OPEB plans, expense for 2007 was $233 million and the total liability, which reflected the underfunded status of the plans at the end of 2007, was $2.9 billion.
     As an indication of discount rate sensitivity to the determination of OPEB expense in 2007, a 1 percent increase in the discount rate for the company’s primary U.S. OPEB plan, which accounted for about 75 percent of the companywide OPEB expense, would have decreased OPEB expense by approximately $20 million. A 0.25 percent increase in the discount rate for the same plan, which accounted for about 87 percent of the companywide OPEB liabilities, would have decreased total OPEB liabilities at the end of 2007 by approximately $60 million.
     For the main U.S. postretirement medical plan, the annual increase to company contributions is limited to 4 percent per year. The cap becomes effective in the year of retirement for pre-Medicare-eligible employees retiring on or after January 1, 2005. The cap was effective as of January 1, 2005, for pre-Medicare-eligible employees retiring before that date and all Medicare-eligible retirees. For active employees and retirees under age 65 whose claims experiences are combined for rating purposes, the assumed health care cost-trend rates start with 8 percent in 2008 and gradually drop to 5 percent for 2014 and beyond. As an indication of the health care cost-trend rate sensitivity to the determination of
OPEB expense in 2007, a 1 percent increase in the rates for the main U.S. OPEB plan, which accounted for about 87 percent of the companywide OPEB liabilities, would have increased OPEB expense $8 million.
     Differences between the various assumptions used to determine expense and the funded status of each plan and actual experience are not included in benefit plan costs in the year the difference occurs. Instead, the differences are included in actuarial gain/loss and unamortized amounts have been reflected in “Accumulated other comprehensive loss” on the Consolidated Balance Sheet. Refer to Note 20, beginning on page FS-48, for information on the $3.3 billion of before-tax actuarial losses recorded by the company as of December 31, 2007; a description of the method used to amortize those costs; and an estimate of the costs to be recognized in expense during 2008.
     Impairment of Properties, Plant and Equipment and Investments in Affiliates  The company assesses its properties, plant and equipment (PP&E) for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in the company’s business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved-reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.
     Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for global or regional market supply and demand conditions for crude oil, natural gas, commodity chemicals and refined products. However, the impairment reviews and calculations are based on assumptions that are consistent with the company’s business plans and long-term investment decisions.
     No major individual impairments of PP&E were recorded for the three years ending December 31, 2007. An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.
     Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the


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fair value of the investment falls below the company’s carrying value. When such a decline is deemed to be other than temporary, an impairment charge is recorded to the income statement for the difference between the investment’s carrying value and its estimated fair value at the time. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. Differing assumptions could affect whether an investment is impaired in any period or the amount of the impairment and are not subject to sensitivity analysis.
     From time to time, the company performs impairment reviews and determines that no write-down in the carrying value of an asset or asset group is required. For example, when significant downward revisions to crude oil and natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the carrying value of the asset remains recoverable. Also, if the expectation of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed of. Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision is made to sell such assets. That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets’ associated carrying values.
     Business CombinationsPurchase-Price Allocation   Accounting for business combinations requires the allocation of the company’s purchase price to the various assets and liabilities of the acquired business at their respective fair values. The company uses all available information to make these fair value determinations, and for major acquisitions, may hire an independent appraisal firm to assist in making fair value estimates. In some instances, assumptions with respect to the timing and amount of future revenues and expenses associated with an asset might have to be used in determining its fair value. Actual timing and amount of net cash flows from revenues and expenses related to that asset over time may differ materially from those initial estimates, and if the timing is delayed significantly or if the net cash flows decline significantly, the asset could become impaired.
     Goodwill  Goodwill resulting from a business combination is not subject to amortization. As required by FASB Statement No. 142, Goodwill and Other Intangible Assets, the company tests such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.
     Contingent Losses  Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters and environmental remediation. Actual costs can frequently vary from estimates for a variety of reasons. For example, the costs
from settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the amount of damages. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology.
     Under the accounting rules, a liability is generally recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally records these losses as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income. An exception to this handling is for income tax matters, for which benefits are recognized only if management determines the tax position is “more likely than not” (i.e. likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For additional discussion of income tax uncertainties, refer to Note 15 beginning on page FS-43. Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, and environmental remediation and tax matters for the three years ended December 31, 2007.
     An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss.

New Accounting Standards

FASB Statement No. 157, Fair Value Measurements (FAS 157)  In September 2006, the FASB issued FAS 157, which became effective for the company on January 1, 2008. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. FAS 157 does not require any new fair value measurements but applies to assets and liabilities that are required to be recorded at fair value under other accounting standards. The implementation of FAS 157 did not have a material effect on the company’s results of operations or consolidated financial position.
     FASB Staff Position FAS No. 157-1, Application of FASB Statement No. 157 to FASB Statement No. 13 and Its Related Interpretive Accounting Pronouncements That Address Leasing Transactions (FSP 157-1)  In February 2008, the FASB issued FSP 157-1, which became effective for the company on January 1, 2008. This FSP excludes FASB Statement No. 13, Accounting for Leases, and its related interpretive accounting pronouncements from the provisions of FAS 157. Implementation of this standard did not have a material effect on the company’s results of operations or consolidated financial position.
     FASB Staff Position FAS No. 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2)  In February 2008, the FASB issued FSP 157-2, which delays the company’s January 1, 2008, effective date of FAS 157 for all nonfinancial assets and nonfinancial


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

liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until January 1, 2009. Implementation of this standard did not have a material effect on the company’s results of operations or consolidated financial position.
     FASB Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115 (FAS 159)  In February 2007, the FASB issued FAS 159, which became effective for the company on January 1, 2008. This standard permits companies to choose to measure many financial instruments and certain other items at fair value and report unrealized gains and losses in earnings. Such accounting is optional and is generally to be applied instrument by instrument. The implementation of FAS 159 did not have a material effect on the company’s results of operations or consolidated financial position.
     FASB Statement No. 141 (revised 2007), Business Combinations (FAS 141-R)  In December 2007, the FASB issued FAS 141-R, which will become effective for business combination transactions having an acquisition date on or after January 1, 2009. This standard requires the acquiring entity in a business combination to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date to be measured at their respective fair values. The Statement requires acquisition-related costs, as well as restructuring costs the acquirer expects to incur for
which it is not obligated at acquisition date, to be recorded against income rather than included in purchase-price determination. It also requires recognition of contingent arrangements at their acquisition-date fair values, with subsequent changes in fair value generally reflected in income.
     FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (FAS 160)  The FASB issued FAS 160 in December 2007, which will become effective for the company January 1, 2009, with retroactive adoption of the Statement’s presentation and disclosure requirements for existing minority interests. This standard will require ownership interests in subsidiaries held by parties other than the parent to be presented within the equity section of the consolidated statement of financial position but separate from the parent’s equity. It will also require the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the consolidated income statement. Certain changes in a parent’s ownership interest are to be accounted for as equity transactions and when a subsidiary is deconsolidated, any noncontrolling equity investment in the former subsidiary is to be initially measured at fair value. The company does not anticipate the implementation of FAS 160 will significantly change the presentation of its consolidated income statement or consolidated balance sheet.


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Quarterly Results and Stock Market Data
Unaudited

                                                                   
    2007       2006  
Millions of dollars, except per-share amounts   4th Q     3rd Q     2nd Q     1st Q       4th Q     3rd Q     2nd Q     1st Q  
       
Revenues and Other Income
                                                                 
Sales and other operating revenues1,2
  $ 59,900     $ 53,545     $ 54,344     $ 46,302       $ 46,238     $ 52,977     $ 52,153     $ 53,524  
Income from equity affiliates
    1,153       1,160       894       937         1,079       1,080       1,113       983  
Other income
    357       468       856       988         429       155       270       117  
       
Total Revenues and Other Income
    61,410       55,173       56,094       48,227         47,746       54,212       53,536       54,624  
       
Costs and Other Deductions
                                                                 
Purchased crude oil and products2
    38,056       33,988       33,138       28,127         27,658       32,076       32,747       35,670  
Operating expenses
    4,798       4,397       4,124       3,613         4,092       3,650       3,835       3,047  
Selling, general and administrative expenses
    1,833       1,446       1,516       1,131         1,203       1,428       1,207       1,255  
Exploration expenses
    449       295       273       306         547       284       265       268  
Depreciation, depletion and amortization
    2,094       2,495       2,156       1,963         1,988       1,923       1,807       1,788  
Taxes other than on income1
    5,560       5,538       5,743       5,425         5,533       5,403       5,153       4,794  
Interest and debt expense
    7       22       63       74         92       104       121       134  
Minority interests
    35       25       19       28         2       20       22       26  
       
Total Costs and Other Deductions
    52,832       48,206       47,032       40,667         41,115       44,888       45,157       46,982  
       
Income Before Income Tax Expense
    8,578       6,967       9,062       7,560         6,631       9,324       8,379       7,642  
Income Tax Expense
    3,703       3,249       3,682       2,845         2,859       4,307       4,026       3,646  
       
Net Income
  $ 4,875     $ 3,718     $ 5,380     $ 4,715       $ 3,772     $ 5,017     $ 4,353     $ 3,996  
       
Per-Share of Common Stock
                                                                 
Net Income
                                                                 
– Basic
  $ 2.34     $ 1.77     $ 2.52     $ 2.20       $ 1.75     $ 2.30     $ 1.98     $ 1.81  
– Diluted
  $ 2.32     $ 1.75     $ 2.52     $ 2.18       $ 1.74     $ 2.29     $ 1.97     $ 1.80  
       
Dividends
  $ 0.58     $ 0.58     $ 0.58     $ 0.52       $ 0.52     $ 0.52     $ 0.52     $ 0.45  
Common Stock Price Range – High3
  $ 94.86     $ 94.84     $ 84.24     $ 74.95       $ 75.97     $ 67.85     $ 62.88     $ 62.21  
– Low3
  $ 83.79     $ 80.76     $ 74.83     $ 66.43       $ 62.94     $ 60.88     $ 56.78     $ 54.08  
       
 
1 Includes excise, value-added and similar taxes:
    $2,548       $2,550       $2,609       $2,414         $2,498       $2,522       $2,416       $2,115  
2 Includes amounts for buy/sell contracts:
    $       –       $       –       $       –       $       –         $       –       $       –       $       –       $6,725  
3 End of day price.
                                                                 

The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 22, 2008, stockholders of record numbered approximately 214,000. There are no restrictions on the company’s ability to pay dividends.

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Management’s Responsibility for Financial Statements

To the Stockholders of Chevron Corporation

Management of Chevron is responsible for preparing the accompanying Consolidated Financial Statements and the related information appearing in this report. The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgment.
     As stated in its report included herein, the independent registered public accounting firm of PricewaterhouseCoopers LLP has audited the company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).
     The Board of Directors of Chevron has an Audit Committee composed of directors who are not officers or employees of the company. The Audit Committee meets regularly with members of management, the internal auditors and the independent registered public accounting firm to review accounting, internal control, auditing and financial reporting matters. Both the internal auditors and the independent registered public accounting firm have free and direct access to the Audit Committee without the presence of management.

 

 

Management’s Report on Internal Control Over Financial Reporting

The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a–15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2007.

     The effectiveness of the company’s internal control over financial reporting as of December 31, 2007, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.
         
-s- David J. O'Reilly
 
-s- Stephen J. Crowe
 
-s- Mark A. Humphrey
David J. O’Reilly
  Stephen J. Crowe   Mark A. Humphrey
Chairman of the Board
  Vice President   Vice President
and Chief Executive Officer
  and Chief Financial Officer   and Comptroller
 
February 28, 2008
       

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Table of Contents

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of Chevron Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows present fairly, in all material respects, the financial position of Chevron Corporation and its subsidiaries at December 31, 2007, and December 31, 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule; for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Controls Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatements and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control, based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in

the circumstances. We believe that our audits provide a reasonable basis for our opinions.

     As discussed in Note 13 to the Consolidated Financial Statements, the Company changed its method of accounting for buy/sell contracts on April 1, 2006.
     As discussed in Note 15 to the Consolidated Financial Statements, the Company changed its method of accounting for uncertain income tax positions on January 1, 2007.
     As discussed in Note 20 to the Consolidated Financial Statements, the Company changed its method of accounting for defined benefit pension and other postretirement plans on December 31, 2006.
     A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/PricewaterhouseCoopers LLP

San Francisco, California
February 28, 2008



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Consolidated Statement of Income
Millions of dollars, except per-share amounts

                           
    Year ended December 31  
    2007       2006     2005  
         
Revenues and Other Income
                         
Sales and other operating revenues1,2
  $ 214,091       $ 204,892     $ 193,641  
Income from equity affiliates
    4,144         4,255       3,731  
Other income
    2,669         971       828  
         
Total Revenues and Other Income
    220,904         210,118       198,200  
         
Costs and Other Deductions
                         
Purchased crude oil and products2
    133,309         128,151       127,968  
Operating expenses
    16,932         14,624       12,191  
Selling, general and administrative expenses
    5,926         5,093       4,828  
Exploration expenses
    1,323         1,364       743  
Depreciation, depletion and amortization
    8,708         7,506       5,913  
Taxes other than on income1
    22,266         20,883       20,782  
Interest and debt expense
    166         451       482  
Minority interests
    107         70       96  
         
Total Costs and Other Deductions
    188,737         178,142       173,003  
         
Income Before Income Tax Expense
    32,167         31,976       25,197  
Income Tax Expense
    13,479         14,838       11,098  
         
Net Income
  $ 18,688       $ 17,138     $ 14,099  
         
Per-Share of Common Stock
                         
Net Income
                         
– Basic
  $ 8.83       $ 7.84     $ 6.58  
– Diluted
  $ 8.77       $ 7.80     $ 6.54  
         
1 Includes excise, value-added and similar taxes.
  $ 10,121       $ 9,551     $ 8,719  
2 Includes amounts in revenues for buy/sell contracts; associated costs are in “Purchased crude oil and products.”
                         
Refer also to Note 13, on page FS-42.
  $       $ 6,725     $ 23,822  

See accompanying Notes to the Consolidated Financial Statements.

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Consolidated Statement of Comprehensive Income
Millions of dollars

                           
    Year ended December 31  
    2007       2006     2005  
         
Net Income
  $ 18,688       $ 17,138     $ 14,099  
         
Currency translation adjustment
                         
Unrealized net change arising during period
    31         55       (5 )
         
Unrealized holding gain (loss) on securities
                         
Net gain (loss) arising during period
    17         (88 )     (32 )
Reclassification to net income of net realized loss
    2                
         
Total
    19         (88 )     (32 )
         
Derivatives
                         
Net derivatives (loss) gain on hedge transactions
    (10 )       2       (242 )
Reclassification to net income of net realized loss
    7         95       34  
Income taxes on derivatives transactions
    (3 )       (30 )     77  
         
Total
    (6 )       67       (131 )
         
Defined benefit plans
                         
Minimum pension liability adjustment
            (88 )     89  
Actuarial loss
                         
Amortization to net income of net actuarial loss
    356                
Actuarial gain arising during period
    530                
Prior service cost
                         
Amortization to net income of net prior service credits
    (15 )              
Prior service cost arising during period
    204                
Non-sponsored defined benefit plans
    19                
Income taxes on defined benefit plans
    (409 )       50       (31 )
         
Total
    685         (38 )     58  
         
Other Comprehensive Gain (Loss), Net of Tax
    729         (4 )     (110 )
         
Comprehensive Income
  $ 19,417       $ 17,134     $ 13,989  
         
See accompanying Notes to the Consolidated Financial Statements.

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Consolidated Balance Sheet
Millions of dollars, except per-share amounts

                   
    At December 31  
    2007       2006  
         
Assets
                 
Cash and cash equivalents
  $ 7,362       $ 10,493  
Marketable securities
    732         953  
Accounts and notes receivable (less allowance: 2007 – $165; 2006 – $175)
    22,446         17,628  
Inventories:
                 
Crude oil and petroleum products
    4,003         3,586  
Chemicals
    290         258  
Materials, supplies and other
    1,017         812  
             
Total inventories
    5,310         4,656  
Prepaid expenses and other current assets
    3,527         2,574  
         
Total Current Assets
    39,377         36,304  
Long-term receivables, net
    2,194         2,203  
Investments and advances
    20,477         18,552  
Properties, plant and equipment, at cost
    154,084         137,747  
Less: Accumulated depreciation, depletion and amortization
    75,474         68,889  
             
Properties, plant and equipment, net
    78,610         68,858  
Deferred charges and other assets
    3,491         2,088  
Goodwill
    4,637         4,623  
         
Total Assets
  $ 148,786       $ 132,628  
         
Liabilities and Stockholders’ Equity
                 
Short-term debt
  $ 1,162       $ 2,159  
Accounts payable
    21,756         16,675  
Accrued liabilities
    5,275         4,546  
Federal and other taxes on income
    3,972         3,626  
Other taxes payable
    1,633         1,403  
         
Total Current Liabilities
    33,798         28,409  
Long-term debt
    5,664         7,405  
Capital lease obligations
    406         274  
Deferred credits and other noncurrent obligations
    15,007         11,000  
Noncurrent deferred income taxes
    12,170         11,647  
Reserves for employee benefit plans
    4,449         4,749  
Minority interests
    204         209  
         
Total Liabilities
    71,698         63,693  
         
Preferred stock (authorized 100,000,000 shares, $1.00 par value; none issued)
             
Common stock (authorized 4,000,000,000 shares, $0.75 par value; 2,442,676,580 shares issued at December 31, 2007 and 2006)
    1,832         1,832  
Capital in excess of par value
    14,289         14,126  
Retained earnings
    82,329         68,464  
Notes receivable – key employees
    (1 )       (2 )
Accumulated other comprehensive loss
    (2,015 )       (2,636 )
Deferred compensation and benefit plan trust
    (454 )       (454 )
Treasury stock, at cost (2007 – 352,242,618 shares; 2006 – 278,118,341 shares)
    (18,892 )       (12,395 )
         
Total Stockholders’ Equity
    77,088         68,935  
         
Total Liabilities and Stockholders’ Equity
  $ 148,786       $ 132,628  
         
See accompanying Notes to the Consolidated Financial Statements.

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Consolidated Statement of Cash Flows
Millions of dollars

                           
    Year ended December 31  
    2007       2006     2005  
         
Operating Activities
                         
Net income
  $ 18,688       $ 17,138     $ 14,099  
Adjustments
                         
Depreciation, depletion and amortization
    8,708         7,506       5,913  
Dry hole expense
    507         520       226  
Distributions less than income from equity affiliates
    (1,439 )       (979 )     (1,304 )
Net before-tax gains on asset retirements and sales
    (2,315 )       (229 )     (134 )
Net foreign currency effects
    378         259       62  
Deferred income tax provision
    261         614       1,393  
Net decrease (increase) in operating working capital
    685         1,044       (54 )
Minority interest in net income
    107         70       96  
(Increase) in long-term receivables
    (82 )       (900 )     (191 )
(Increase) decrease in other deferred charges
    (530 )       232       668  
Cash contributions to employee pension plans
    (317 )       (449 )     (1,022 )
Other
    326         (503 )     353  
         
Net Cash Provided by Operating Activities
    24,977         24,323       20,105  
         
Investing Activities
                         
Cash portion of Unocal acquisition, net of Unocal cash received
                  (5,934 )
Capital expenditures
    (16,678 )       (13,813 )     (8,701 )
Repayment of loans by equity affiliates
    21         463       57  
Proceeds from asset sales
    3,338         989       2,681  
Net sales of marketable securities
    185         142       336  
Net purchases of other short-term investments
    (799 )              
         
Net Cash Used for Investing Activities
    (13,933 )       (12,219 )     (11,561 )
         
Financing Activities
                         
Net payments of short-term obligations
    (345 )       (677 )     (109 )
Repayments of long-term debt and other financing obligations
    (3,343 )       (2,224 )     (966 )
Proceeds from issuances of long-term debt
    650               20  
Cash dividends – common stock
    (4,791 )       (4,396 )     (3,778 )
Dividends paid to minority interests
    (77 )       (60 )     (98 )
Net purchases of treasury shares
    (6,389 )       (4,491 )     (2,597 )
Redemption of preferred stock of subsidiaries
                  (140 )
         
Net Cash Used for Financing Activities
    (14,295 )       (11,848 )     (7,668 )
         
Effect of Exchange Rate Changes
On Cash and Cash Equivalents
    120         194       (124 )
         
Net Change in Cash and Cash Equivalents
    (3,131 )       450       752  
Cash and Cash Equivalents at January 1
    10,493         10,043       9,291  
         
Cash and Cash Equivalents at December 31
  $ 7,362       $ 10,493     $ 10,043  
         
See accompanying Notes to the Consolidated Financial Statements.

FS-30


Table of Contents

Consolidated Statement of Stockholders’ Equity
Shares in thousands; amounts in millions of dollars

                                                   
    2007       2006     2005  
    Shares     Amount       Shares     Amount     Shares     Amount  
         
Preferred Stock
        $             $           $  
         
Common Stock
                                                 
Balance at January 1
    2,442,677     $ 1,832         2,442,677     $ 1,832       2,274,032     $ 1,706  
Shares issued for Unocal acquisition
                              168,645       126  
             
Balance at December 31
    2,442,677     $ 1,832         2,442,677     $ 1,832       2,442,677     $ 1,832  
         
Capital in Excess of Par
                                                 
Balance at January 1
          $ 14,126               $ 13,894             $ 4,160  
Shares issued for Unocal acquisition
                                          9,585  
Treasury stock transactions
            163                 232               149  
                     
Balance at December 31
          $ 14,289               $ 14,126             $ 13,894  
         
Retained Earnings
                                                 
Balance at January 1
          $ 68,464               $ 55,738             $ 45,414  
Net income
            18,688                 17,138               14,099  
Cash dividends on common stock
            (4,791 )               (4,396 )             (3,778 )
Adoption of EITF 04–6, “Accounting for Stripping Costs Incurred during Production in the Mining Industry”
                            (19 )              
Adoption of FIN 48, “Accounting for Uncertainty in Income Taxes”
            (35 )                              
Tax benefit from dividends paid on unallocated ESOP shares and other
            3                 3               3