Form 10-K
Table of Contents
Index to Financial Statements

2004


UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549


FORM 10-K

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

or

¨    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 1-2256

EXXON MOBIL CORPORATION

(Exact name of registrant as specified in its charter)

 

NEW JERSEY

(State or other jurisdiction of
incorporation or organization)

 

13-5409005

(I.R.S. Employer
Identification Number)

 

5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298

(Address of principal executive offices) (Zip Code)

(972) 444-1000

(Registrant’s telephone number, including area code)


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

Title of Each Class


   Name of Each Exchange
on Which Registered


Common Stock, without par value (6,385,358,170 shares
outstanding at January 31, 2005)

   New York Stock Exchange
Registered securities guaranteed by Registrant:     

SeaRiver Maritime Financial Holdings, Inc.

    

Twenty-Five Year Debt Securities due October 1, 2011

   New York Stock Exchange

Exxon Capital Corporation

    

Twelve Year 6% Notes due July 1, 2005

   New York Stock Exchange

 

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   ü    No        

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.   ü   

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).  Yes   ü    No        

 

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2004, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $44.41 on the New York Stock Exchange composite tape, was in excess of $288 billion.

 

Documents Incorporated by Reference:

    Proxy Statement for the 2005 Annual Meeting of Shareholders (Part III)



Table of Contents
Index to Financial Statements

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2004

 

TABLE OF CONTENTS

 

     Page
Number


PART I
Item 1.   

Business

   1
Item 2.   

Properties

   3
Item 3.   

Legal Proceedings

   18
Item 4.   

Submission of Matters to a Vote of Security Holders

   18
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]    19
PART II
Item 5.   

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities

   20
Item 6.   

Selected Financial Data

   21
Item 7.    Management’s Discussion and Analysis of Financial Condition and
    Results of Operations
   21
Item 7A.   

Quantitative and Qualitative Disclosures About Market Risk

   21
Item 8.   

Financial Statements and Supplementary Data

   22
Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    22
Item 9A.    Controls and Procedures    22
Item 9B.    Other Information    22
PART III
Item 10.   

Directors and Executive Officers of the Registrant

   23
Item 11.   

Executive Compensation

   23
Item 12.   

Security Ownership of Certain Beneficial Owners and Management

   23
Item 13.   

Certain Relationships and Related Transactions

   23
Item 14.   

Principal Accounting Fees and Services

   23
PART IV
Item 15.   

Exhibits, Financial Statement Schedules

   23
Financial Section    25
Signatures    90
Index to Exhibits    92
Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges     
Exhibits 31 and 32 — Certifications     


Table of Contents
Index to Financial Statements

PART I

 

Item 1.     Business.

 

Exxon Mobil Corporation, formerly named Exxon Corporation, was incorporated in the State of New Jersey in 1882. On November 30, 1999, Mobil Corporation became a wholly-owned subsidiary of Exxon Corporation, and Exxon changed its name to Exxon Mobil Corporation.

 

Divisions and affiliated companies of ExxonMobil operate or market products in the United States and about 200 other countries and territories. Their principal business is energy, involving exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a major manufacturer and marketer of basic petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. ExxonMobil also has interests in electric power generation facilities. Affiliates of ExxonMobil conduct extensive research programs in support of these businesses.

 

Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include ExxonMobil, Exxon, Esso or Mobil. For convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso and Mobil, as well as terms like Corporation, Company, our, we and its, are sometimes used as abbreviated references to specific affiliates or groups of affiliates. The precise meaning depends on the context in question.

 

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on the air, water and ground. This includes a significant investment in refining technology to manufacture low-sulfur motor fuels and projects to reduce nitrogen oxide and sulfur oxide emissions. ExxonMobil’s 2004 worldwide environmental costs for all such preventative and remediation steps were about $2.9 billion, of which $1.1 billion were capital expenditures and $1.8 billion were included in expenses. The total cost for such activities is expected to be about $3.0 billion in 2005 (with capital expenditures representing just over 40 percent of the total) and a similar amount is expected for 2006.

 

Operating data and industry segment information for the Corporation are contained on pages 75, 76, 88 and 89; information on oil and gas reserves is contained on pages 82 through 85 and information on Company-sponsored research and development activities is contained on page 57 of the Financial Section of this report.

 

The number of regular employees was 85.9 thousand, 88.3 thousand and 92.5 thousand at years ended 2004, 2003 and 2002, respectively. Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs. Regular employees do not include employees of the company-operated retail sites (CORS). The number of CORS employees was 19.3 thousand, 17.4 thousand and 16.8 thousand at years ended 2004, 2003 and 2002, respectively.

 

ExxonMobil maintains a website at www.exxonmobil.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission. Also available on the Corporation’s website are the Company’s Corporate Governance Guidelines and Code of Ethics and Business Conduct, as well as the charters of the audit, compensation and nominating committees of the board of directors. All of these documents are available in print without charge to shareholders who request them. Information on our website is not incorporated into this report.

 

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Index to Financial Statements

Factors Affecting Future Results

 

Competitive Factors:    The energy and petrochemical industries are highly competitive. There is competition within the industries and also with other industries in supplying the energy, fuel and chemical needs of industry and individual consumers. The Corporation competes with other firms in the sale or purchase of various goods or services in many national and international markets and employs all methods of competition which are lawful and appropriate for such purposes. A key component of the Corporation’s competitive position, particularly given the commodity-based nature of many of its products, is its ability to manage expenses successfully, which requires continuous management focus on reducing unit costs and improving efficiency.

 

Political Factors:    The operations and earnings of the Corporation and its affiliates throughout the world have been, and may in the future be, affected from time to time in varying degree by political instability and by other political developments and laws and regulations, such as forced divestiture of assets; restrictions on production, imports and exports; war or other international conflicts; civil unrest and local security concerns that threaten the safe operation of company facilities; price controls; tax increases and retroactive tax claims; expropriation of property; cancellation of contract rights; and environmental regulations. Both the likelihood of such occurrences and their overall effect upon the Corporation vary greatly from country to country and are not predictable.

 

Industry and Economic Factors:    The operations and earnings of the Corporation and its affiliates throughout the world are affected by local, regional and global events or conditions that affect supply and demand for oil, natural gas, petroleum products, petrochemicals and other ExxonMobil products. These events or conditions are generally not predictable and include, among other things, general economic growth rates and the occurrence of economic recessions; the development of new supply sources; adherence by countries to OPEC quotas; supply disruptions; weather, including seasonal patterns that affect energy demand and severe weather events that can disrupt operations; technological advances, including advances in exploration, production, refining, and petrochemical manufacturing technology and advances in technology relating to energy usage; changes in demographics, including population growth rates and consumer preferences; and the competitiveness of alternative hydrocarbon or other energy sources or product substitutes.

 

Project Factors:    In addition to the factors cited above, the advancement, cost and results of particular ExxonMobil projects depend on the outcome of negotiations with partners, governments, suppliers, customers or others; changes in operating conditions or costs; changes in rates of field decline; and the occurrence of unforeseen technical difficulties. See section 1 of Item 2 of this report for discussion of additional factors affecting future capacity growth and the timing and ultimate recovery of reserves.

 

Market Risk Factors:    See pages 39 and 40 of the Financial Section of this report for discussion of the impact of market risks, inflation and other uncertainties.

 

Projections, estimates and descriptions of ExxonMobil’s plans and objectives included or incorporated in Items 1, 2, 7 and 7A of this report are forward-looking statements. Actual future results, including project completion dates, production rates, capital expenditures, costs and business plans could differ materially due to, among other things, the factors discussed above and elsewhere in this report.

 

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Index to Financial Statements

Item 2.    Properties.

 

Part of the information in response to this item and to the Securities Exchange Act Industry Guide 2 is contained in the Financial Section of this report in Note 9, which note appears on page 59, and on pages 78 through 87.

 

Information with regard to oil and gas producing activities follows:

 

1.    Net Reserves of Crude Oil and Natural Gas Liquids and Natural Gas at Year-End 2004

 

Estimated proved reserves are shown on pages 82 through 85 of the Financial Section of this report. No major discovery or other favorable or adverse event has occurred since December 31, 2004, that would cause a significant change in the estimated proved reserves as of that date, with the exception of bitumen prices in western Canada which have increased substantially from December 31. This price increase resulted in the rebooking, in 2005, of approximately 0.5 billion oil-equivalent barrels at the Cold Lake field. For information on the standardized measure of discounted future net cash flows relating to proved oil and gas reserves, see pages 86 and 87 of the Financial Section of this report.

 

The table below summarizes the oil-equivalent proved reserves in each geographic area for consolidated subsidiaries as detailed on pages 82 through 85 of the Financial Section of this report for the year ended December 31, 2004. The Corporation has reported 2004 proved reserves on the basis of December 31, 2004 prices and costs for the first time. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

 

     United
States


   Canada

   Europe

  

Asia

Pacific


   Africa

  

Middle

East


   Other

   Total
Consolidated


     (millions of barrels)

Liquids

   2,593    627    1,014    601    2,444    49    1,067    8,395
     (billions of cubic feet)

Natural gas

   12,329    1,883    9,185    5,919    771    684    1,072    31,843
     (millions of oil-equivalent barrels)

Oil-equivalent basis

   4,648    941    2,545    1,587    2,572    163    1,246    13,702

 

Additional detail on developed and undeveloped oil-equivalent proved reserves is shown in the table below.

 

     Year-End 2004

   Year-End 2003

     Developed

   Undeveloped

   Developed

   Undeveloped

     (millions of oil-equivalent barrels)

Consolidated Subsidiaries

                   

United States

   3,726    922    3,934    737

Canada

   836    105    1,077    507

Europe

   1,942    603    2,004    871

Asia Pacific

   1,132    455    1,433    465

Africa

   1,164    1,408    1,133    1,706

Middle East

   11    152    20    190

Caspian region

   34    606    33    726

South America

   176    430    187    432
    
  
  
  

Total

   9,021    4,681    9,821    5,634
    
  
  
  

Equity Companies

                   

United States

   367    59    383    68

Europe

   1,649    627    1,311    993

Middle East

   1,404    2,007    1,064    712

Caspian region

   740    399    632    585
    
  
  
  

Total

   4,160    3,092    3,390    2,358
    
  
  
  

 

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Index to Financial Statements

In the preceding reserves information, and in the reserves tables on pages 82 through 85 of the Financial Section of this report, consolidated subsidiary and equity company reserves are reported separately. However, the Corporation operates its business with the same views of equity company reserves as it has for reserves from consolidated subsidiaries.

 

The Corporation’s overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity increases to average 3 percent annually through 2010. However, actual volume increases will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, price effects on production sharing contracts and other factors as described under the heading “Factors Affecting Future Results” in Item 1 of this report.

 

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations and extrapolations of well information such as flow rates and reservoir pressure declines. In certain deepwater fields, proved reserves are recorded in a limited number of cases before flow tests are conducted because of the safety and cost implications of conducting the tests. In those situations, other industry accepted analyses are used such as information from well logs, a thorough pressure and fluid sampling program, conventional core data obtained across the entire reservoir interval and nearby analog data. Historically, proved reserves recorded using these methods have been immaterial when compared to the Corporation’s total proved reserves and have also been validated by subsequent flow tests or actual production levels. Furthermore, the Corporation only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in projections of long term oil and gas price levels.

 

2.    Estimates of Total Net Proved Oil and Gas Reserves Filed with Other Federal Agencies

 

During 2004, ExxonMobil filed proved reserves estimates with the U.S. Department of Energy on Forms EIA-23 and EIA-28. The information on Form EIA-28 is presented on the same basis as the registrant’s Annual Report on Form 10-K for 2003, which shows ExxonMobil’s net interests in all liquids and gas reserve volumes and changes thereto from both ExxonMobil-operated properties and properties operated by others. The data on Form EIA-23, although consistent with the data on Form EIA-28, is presented on a different basis, and includes 100 percent of the oil and gas volumes from ExxonMobil-operated properties only, regardless of the company’s net interest. In addition, Form EIA-23 information does not include gas plant liquids. The difference between the oil reserves reported on EIA-23 and those reported in the registrant’s Annual Report on Form 10-K for 2003 exceeds five percent. The difference in gas reserves did not exceed five percent.

 

3.    Average Sales Prices and Production Costs per Unit of Production

 

Reference is made to pages 78 and 79 of the Financial Section of this report. Average sales prices have been calculated by using sales quantities from the Corporation’s own production as the divisor. Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the reserves table on page 83 of the Financial Section of this report. The volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and thus are different from those shown in the reserves table on page 84 of the Financial Section of this report due to volumes consumed or flared. The volumes of natural gas were converted to oil-equivalent barrels based on a conversion factor of six thousand cubic feet per barrel.

 

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Index to Financial Statements

4.    Gross and Net Productive Wells

 

     Year-End 2004

   Year-End 2003

     Oil

   Gas

   Oil

   Gas

     Gross

   Net

   Gross

   Net

   Gross

   Net

   Gross

   Net

United States

   30,702    11,949    9,335    5,577    33,716    13,188    9,566    5,746

Canada

   7,156    5,890    5,663    2,752    7,037    5,770    5,317    2,666

Europe

   1,872    594    1,304    520    1,873    604    1,387    524

Asia Pacific

   1,154    433    193    164    1,509    553    853    306

Africa

   562    235    18    7    355    152    16    7

Middle East

   924    144    42    8    1,010    150    35    6

Other

   240    78    67    25    229    74    66    24
    
  
  
  
  
  
  
  

Total

   42,610    19,323    16,622    9,053    45,729    20,491    17,240    9,279
    
  
  
  
  
  
  
  

 

The numbers of wells operated at year-end 2004 were 18,427 gross wells and 15,216 net wells. At year-end 2003, the numbers of operated wells were 20,174 gross wells and 16,610 net wells.

 

5.    Gross and Net Developed Acreage

 

     Year-End 2004

   Year-End 2003

     Gross

   Net

   Gross

   Net

     (thousands of acres)

United States

   9,017    5,480    9,367    5,655

Canada

   5,535    2,499    4,786    2,431

Europe

   11,345    4,715    11,296    4,746

Asia Pacific

   2,700    1,080    5,443    1,723

Africa

   1,179    475    1,130    462

South America

   1,331    388    1,331    388

Middle East

   7,416    1,356    7,405    1,356

Caspian

   487    103    487    103
    
  
  
  

Total

   39,010    16,096    41,245    16,864
    
  
  
  

 

Note: Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage.

 

6.    Gross and Net Undeveloped Acreage

 

     Year-End 2004

   Year-End 2003

     Gross

   Net

   Gross

   Net

     (thousands of acres)

United States

   10,913    7,055    11,343    7,353

Canada

   10,440    5,997    9,078    5,055

Europe

   8,418    2,245    8,555    2,611

Asia Pacific

   7,935    4,219    17,457    8,769

Africa

   41,380    21,797    28,423    11,447

South America

   27,020    19,688    15,650    15,141

Middle East

   154    46    36    10

Caspian

   2,322    476    2,561    516
    
  
  
  

Total

   108,582    61,523    93,103    50,902
    
  
  
  

 

ExxonMobil’s investment in developed and undeveloped acreage is comprised of numerous concessions, blocks and leases. The terms and conditions under which the Corporation maintains exploration and/or production rights to the acreage are property-specific, contractually-defined and vary significantly. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, the Corporation may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, the Corporation has generally been successful in obtaining extensions.

 

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Index to Financial Statements

7.     Summary of Acreage Terms in Key Areas

 

UNITED STATES

 

Oil and gas leases have an exploration period ranging from one to ten years, and a production period that normally remains in effect until production ceases. In some instances, a “fee interest” is acquired where both the surface and the underlying mineral interests are owned outright.

 

CANADA

 

Exploration permits are granted for varying periods of time with renewals possible. Production leases are held as long as there is production on the lease. The majority of Cold Lake leases were taken for an initial 21-year term in 1968-1969 and renewed for a second 21-year term in 1989-1990. The exploration acreage in eastern Canada is currently held by work commitments of various amounts.

 

EUROPE

 

France

 

Exploration permits are granted for periods of three to five years, and are renewable up to two times accompanied by substantial acreage relinquishments: 50 percent of the acreage at first renewal; 25 percent of the remaining acreage at second renewal. A 1994 law requires a bidding process prior to granting of an exploration permit. Upon discovery of commercial hydrocarbons, a production concession is granted for up to 50 years, renewable in periods of 25 years each.

 

Germany

 

Exploration concessions are granted for an initial maximum period of five years with possible extensions of up to three years for an indefinite period. Extensions are subject to specific, minimum work commitments. Production licenses are normally granted for 20 to 25 years with multiple possible extensions as long as there is production on the license.

 

Netherlands

 

Under the new Mining Law, effective January 1, 2003, exploration and production licenses for both onshore and offshore areas are issued for a period of time necessary to perform the activities for which the license is issued. License conditions are stipulated in the Mining Law.

 

Exploration and production rights granted prior to January 1, 2003 remain subject to their existing terms, and differ slightly for onshore and offshore areas.

 

Onshore:  Exploration licenses were issued for a period of time necessary to perform the activities for which the license was issued. Production concessions are granted after discoveries have been made, under conditions that are negotiated with the government. Normally, they are field-life concessions covering an area defined by hydrocarbon occurrences.

 

Offshore:  Exploration licenses issued between 1976 and 1996 were for a ten-year period, with relinquishment of about 50 percent of the original area required at the end of six years. Exploration licenses granted after that time were for a period of time necessary to perform the activities for which the permit was issued. Production licenses are normally issued for a 40-year period.

 

Norway

 

Licenses issued prior to 1972 were for an initial period of six years and an extension period of 40 years, with relinquishment of at least one-fourth of the original area required at the end of the sixth

 

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Index to Financial Statements

year and another one-fourth at the end of the ninth year. Licenses issued between 1972 and 1997 were for an initial period of up to six years (with extension of the initial period of one year at a time up to ten years after 1985), and an extension period of up to 30 years, with relinquishment of at least one-half of the original area required at the end of the initial period. Licenses issued after July 1, 1997 have an initial period of up to ten years and a normal extension period of up to 30 years or in special cases of up to 50 years, and with relinquishment of at least one-half of the original area required at the end of the initial period.

 

United Kingdom

 

Acreage terms are fixed by the government and are periodically changed. For example, the regulations governing licenses issued between 1996 and 1998 provided for an initial term of three years with possible extensions of six, 15 and 24 years for a license period of 45 more years. After the second extension, the license must be surrendered in part. Licenses issued in 2002 as part of the 20th licensing round have an initial term of four years with a second term extension of four years. There is a mandatory relinquishment of all acreage that is not covered by a development plan at the end of the second term.

 

ASIA PACIFIC

 

Australia

 

Exploration and production activities are conducted offshore and are governed by Federal legislation. Exploration permits granted before January 1, 2003 were issued for six years with three possible five-year renewal periods. Exploration permits granted after that date are issued for six years with two possible five-year renewal periods. A 50 percent relinquishment of remaining area is mandatory at the end of each renewal period. Retention leases may be granted for resources that are not commercially viable at the time of application, but are expected to become commercially viable within 15 years. These are granted for periods of five years and renewals may be requested. Prior to September 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter renewals at the discretion of the Joint Authority, comprising Federal and State Ministers. Effective from September 1998, new production licenses are granted “indefinitely”, i.e., for the life of the field (if no operations for the recovery of petroleum have been carried on for five years, the license may be terminated).

 

Indonesia

 

Exploration and production activities in Indonesia are generally governed by cooperation contracts, usually in the form of a production sharing contract, negotiated with BPMIGAS, a government agency established in 2002 to manage upstream oil and gas activities. Formerly this activity was carried out by Pertamina, the government owned oil company, which is now a competing limited liability company.

 

Japan

 

The Mining Law provides for the granting of concessions that convey exploration and production rights. Exploration rights are granted for an initial two-year period, and may be extended for two two-year periods for gas and three two-year periods for oil. Production rights have no fixed term and continue until abandonment so long as the rights holder is fulfilling its obligations.

 

Malaysia

 

Exploration and production activities are governed by production sharing contracts negotiated with the national oil company. The more recent contracts have an overall term of 24 to 38 years with

 

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Index to Financial Statements

possible extensions to the exploration and/or development periods. The exploration period is five to seven years with the possibility of extensions, after which time areas with no commercial discoveries will be deemed relinquished. The development period is from four to six years from commercial discovery, with the possibility of extensions under special circumstances. Areas from which commercial production has not started by the end of the development period will be deemed relinquished if no extension is granted. All extensions are subject to the national oil company’s prior written approval. The total production period is 15 to 25 years from first commercial lifting, not to exceed the overall term of the contract.

 

Papua New Guinea

 

Exploration and production activities are governed by the Oil and Gas Act. Petroleum Prospecting licenses are granted for an initial term of six years with a five-year extension possible. Generally, a 50 percent relinquishment of the license area is required at the end of the initial six-year term, if extended. Petroleum Development licenses are granted for an initial 25-year period. An extension of up to 20 years may be granted at the Minister’s discretion. Petroleum Retention licenses may be granted for gas resources that are not commercially viable at the time of application, but may become commercially viable. Petroleum Retention licenses are granted for five-year terms, and may be extended twice for a maximum retention time of 15 years.

 

Russia

 

Acreage terms are fixed by the production sharing agreement (PSA) that became effective in 1996 between the Russian government and the Sakhalin I consortium, of which ExxonMobil is the operator. The term of the PSA is 20 years from the Declaration of Commerciality, which would be 2021. The term may be extended thereafter in 10-year increments as specified in the PSA.

 

Thailand

 

The Petroleum Act of 1971 allows production under ExxonMobil’s concession for 30 years with a possible ten-year extension at terms generally prevalent at the time.

 

AFRICA

 

Angola

 

Exploration and production activities are governed by production sharing agreements with an initial exploration term of four years and an optional second phase of two to three years. The production period is for 25 years and agreements generally provide for a negotiated extension.

 

Cameroon

 

Exploration and production activities are governed by various agreements negotiated with the national oil company and the government of Cameroon. Exploration permits are granted for terms from four to 16 years and are generally renewable for multiple periods up to four years each. Upon commercial discovery, mining concessions are issued for a period of 25 years with one 25-year extension.

 

Chad

 

Exploration permits are issued for a period of five years, and are renewable for one or two further five-year periods. The terms and conditions of the permits, including relinquishment obligations, are specified in a negotiated Convention. The production term is for 30 years and may be extended at the discretion of the government.

 

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Equatorial Guinea

 

Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines and Energy. The exploration periods are for ten to 15 years with limited relinquishments in the absence of commercial discoveries. The production period for crude oil is 30 years while the production period for gas is 50 years.

 

Nigeria

 

Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with the national oil company, the Nigerian National Petroleum Corporation (NNPC). NNPC holds the underlying Oil Prospecting License (OPL) and any resulting Oil Mining Lease (OML). The terms of the PSCs are generally 30 years, including a ten-year exploration period (an initial exploration phase plus one or two optional periods) covered by an OPL. Upon commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required under the PSC at the end of the ten-year exploration period, and OMLs have a 20-year production period that may be extended.

 

Some exploration activities are carried out in deepwater by joint ventures with local companies holding interests in an OPL. OPLs in deepwater offshore areas are valid for ten years and are non-renewable, while in all other areas the licenses are for five years and also are non-renewable. Demonstrating a commercial discovery is the basis for conversion of an OPL to an OML.

 

OMLs granted prior to the 1969 Petroleum Act (i.e., under the Mineral Oils Act 1914, repealed by the 1969 Petroleum Act) were for 30 years onshore and 40 years in offshore areas and are renewable upon 12 months’ written notice, for further periods of 30 and 40 years, respectively. Operations under these pre-1969 OMLs are conducted under a joint venture agreement with NNPC rather than a PSC.

 

OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs, have a maximum term of 20 years without distinction for onshore or offshore location and are renewable, upon 12 months’ written notice, for another period of 20 years. OMLs not held by NNPC are also subject to a mandatory 50 percent relinquishment after the first ten years of their duration.

 

The Memorandum of Understanding (MOU) defining commercial terms applicable to existing joint venture oil production was renegotiated and executed in 2000. The MOU is effective for a minimum of three years with possible extensions on mutual agreement and is terminable on one calendar year’s notice.

 

SOUTH AMERICA

 

Argentina

 

The onshore concession terms in Argentina are up to four years for the initial exploration period, up to three years for the second exploration period and up to two years for the third exploration period. A 50 percent relinquishment is required after each exploration period. An extension after the third exploration period is possible for up to five years. The total production term is 25 years with a ten-year extension possible, once a field has been developed.

 

Venezuela

 

Exploration and production activities are governed by contracts negotiated with the national oil company. Exploration activity is covered by risk/profit sharing contracts where exploration blocks are awarded for 35 years. Production licenses are awarded for 20 years under production service agreements.

 

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Index to Financial Statements

Strategic association agreements (such as the Cerro Negro project) are typically limited to those projects that require vertical integration for extra heavy crude oil. Contracts are awarded for 35 years. Significant amendments to the contract terms require Venezuelan congressional approval.

 

MIDDLE EAST

 

Qatar

 

The State of Qatar grants gas production development project rights to develop and supply gas from the offshore North Field to permit the economic development and production of gas reserves sufficient to satisfy the gas and LNG sales obligations of these projects.

 

Republic of Yemen

 

Production sharing agreements (PSAs) negotiated with the government entitle the company to participate in exploration operations within a designated area during the exploration period. In the event of a commercial oil discovery, the company is entitled to proceed with development and production operations during the development period. The length of these periods and other specific terms are negotiated prior to executing the PSA. Existing production operations have a development period extending 20 years from first commercial declaration made in November 1985 for the Marib PSA and June 1995 for the Jannah PSA.

 

United Arab Emirates

 

Exploration and production activities in the Emirate of Abu Dhabi are governed by a 75-year oil concession agreement executed in 1939 and subsequently amended through various agreements with the government of Abu Dhabi.

 

CASPIAN

 

Azerbaijan

 

The production sharing agreement (PSA) for the development of the Azeri-Chirag-Gunashli field (commonly known as the Megastructure) is established for an initial period of 30 years starting from the PSA execution date in 1994.

 

Other exploration and production activities are governed by PSAs negotiated with the national oil company of Azerbaijan. The exploration period consists of three or four years with the possibility of a one to three-year extension. The production period, which includes development, is for 25 years or 35 years with the possibility of one or two five-year extensions.

 

Kazakhstan

 

Onshore:  Exploration and production activities are governed by the production license, exploration license and joint venture agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993.

 

Offshore:  Exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period is six years with possible extensions. The production period, which includes development, is for 20 years with the possibility of two ten-year extensions.

 

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Index to Financial Statements

8.    Number of Net Productive and Dry Wells Drilled

 

     2004

   2003

   2002

 

A. Net Productive Exploratory Wells Drilled

                

United States

   11    13    12  

Canada

   2    13    20  

Europe

   3    4    2  

Asia Pacific

   2    2    2  

Africa

   2    4    10  

Middle East

          

Other

   1    2     
    
  
  

Total

   21    38    46  
    
  
  

B. Net Dry Exploratory Wells Drilled

                

United States

   6    10    5  

Canada

   4    9    4  

Europe

   1    3    4  

Asia Pacific

      3    1  

Africa

   4    3    5  

Middle East

          

Other

         4  
    
  
  

Total

   15    28    23  
    
  
  

C. Net Productive Development Wells Drilled

                

United States

   568    598    709  

Canada

   466    297    430  

Europe

   24    36    36  

Asia Pacific

   23    50    67  

Africa

   64    59    27  

Middle East

   12    17    15  

Other

   7    3    3  
    
  
  

Total

   1,164    1,060    1,287  
    
  
  

D. Net Dry Development Wells Drilled

                

United States

   13    14    18  

Canada

   2    16    8  

Europe

   2    2    2  

Asia Pacific

         1  

Africa

      1     

Middle East

   1    1     

Other

          
    
  
  

Total

   18    34    29  
    
  
  

Total number of net wells drilled

   1,218    1,160    1,385  
    
  
  

 

9.    Present Activities

 

A. Wells Drilling

 

     Year-End 2004

   Year-End 2003

     Gross

   Net

   Gross

   Net

United States

   179    81    132    62

Canada

   31    17    152    92

Europe

   32    8    38    12

Asia Pacific

   20    11    10    5

Africa

   80    33    78    27

Middle East

   38    16    18    3

Other

   28    4    24    3
    
  
  
  

Total

   408    170    452    204
    
  
  
  

 

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Index to Financial Statements

B.    Review of Principal Ongoing Activities in Key Areas

 

During 2004, ExxonMobil’s activities were conducted, either directly or through affiliated companies, by ExxonMobil Exploration Company (for exploration), by ExxonMobil Development Company (for large development activities), by ExxonMobil Production Company (for producing and smaller development activities) and by ExxonMobil Gas & Power Marketing Company (for gas marketing). During this same period, some of ExxonMobil’s exploration, development, production and gas marketing activities were also conducted in Canada by the Resources Division of Imperial Oil Limited, which is 69.6 percent owned by ExxonMobil.

 

Some of the more significant ongoing activities are set forth below:

 

UNITED STATES

 

Exploration and delineation of additional hydrocarbon resources continued in 2004. At year-end 2004, ExxonMobil’s acreage totaled 12.5 million net acres, of which 3.3 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska. A total of 16.6 net exploration and delineation wells were completed during 2004.

 

During 2004, 542.5 net development wells were completed within and around mature fields in the inland lower 48 states and 8.0 net development wells were completed offshore in the Pacific. Construction continued on an acid gas injection project to increase existing plant capacity at the Shute Creek treating facility in La Barge, Wyoming, and tight gas development has been initiated in the Piceance Basin in Colorado. Participation in Alaska production and development continued and a total of 21.8 net development wells were drilled. On Alaska’s North Slope, activity continued on the Western Region Development Project (primarily the Orion field) with development drilling and conceptual engineering for facility expansions.

 

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2004 was 3.1 million acres. A total of 8.1 net development wells were completed during the year and development continued on several Gulf of Mexico projects. Production began from the South Diana subsea deepwater field in March 2004. Production began from the first phase of the Llano subsea development in May 2004. Hull construction was completed and topsides construction continued on the semi-submersible production and drilling vessel for the Thunder Horse development.

 

CANADA

 

ExxonMobil’s year-end 2004 acreage holdings totaled 8.5 million net acres, of which 4.1 million net acres were offshore. A total of 474.4 net exploration and development wells were completed during the year.

 

Gross production from Cold Lake averaged 126 thousand barrels per day during 2004. In eastern Canada, the South Venture field of the Sable Offshore Energy Project came online.

 

EUROPE

 

France

 

ExxonMobil’s acreage at year-end 2004 was 0.1 million net onshore acres, with 1.0 net exploration and development well completed during the year.

 

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Index to Financial Statements

Germany

 

A total of 2.3 million net onshore acres and 0.2 million net offshore acres were held by ExxonMobil at year-end 2004, with 4.3 net exploration and development wells completed during the year.

 

Netherlands

 

ExxonMobil’s interest in licenses totaled 1.9 million net acres at year-end 2004, 1.5 million acres onshore and 0.4 million acres offshore. During 2004, 1.6 net exploration and development wells were drilled. Offshore, the K/7-FB field began production in late December 2003, and the K/15-FB-South field began production in July 2004. Onshore, a multi-year project is underway to renovate production clusters and install new compression to maintain capacity and extend field life.

 

Norway

 

ExxonMobil’s net interest in licenses at year-end 2004 totaled approximately 1.1 million acres, all offshore. ExxonMobil participated in 12.6 net exploration and development well completions in 2004. Production was initiated at the Ringhorne Jurassic field in March 2004, at the Vigdis East field in May 2004, and at the Sleipner West Alpha North field and the Sleipner West compression project in October 2004. New development projects at Kristin and Ormen Lange are in progress.

 

United Kingdom

 

ExxonMobil’s net interest in licenses at year-end 2004 totaled approximately 1.3 million acres, all offshore. A total of 10.8 net exploration and development wells were completed during the year. The Goldeneye project started first production in late 2004. The Arthur field project was progressed in 2004 and production was initiated early in 2005. Project development progressed on the Cutter field.

 

ASIA PACIFIC

 

Australia

 

ExxonMobil’s net year-end 2004 acreage holdings totaled 1.4 million acres, all offshore. ExxonMobil drilled a total of 3.9 net exploration and development wells in 2004.

 

Indonesia

 

ExxonMobil had acreage of 2.7 million net acres at year-end 2004, 1.7 million acres offshore and 1.0 million acres onshore.

 

Japan

 

ExxonMobil’s net offshore acreage was 36 thousand acres at year-end 2004.

 

Malaysia

 

ExxonMobil had interests in production sharing contracts covering 0.5 million net acres offshore Malaysia at year-end 2004. During the year, a total of 20.2 net exploration and development wells were completed. Development and infill drilling wells were successfully completed at eight platforms: Guntong-C, Semangkok-A, Semangkok-B, Larut-A, Tapis-F, Angsi-A, Angsi-C and Angsi-E. First oil was produced from Tapis-F in 2004. Drilling activities are currently ongoing at Semangkok-B, Irong Barat-C and Angsi-A.

 

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Index to Financial Statements

Papua New Guinea

 

A total of 0.6 million net onshore acres were held by ExxonMobil at year-end 2004, with 0.8 net development wells completed during the year.

 

Russia

 

ExxonMobil’s net acreage holdings at year-end 2004 were 85 thousand acres, all offshore. Construction and drilling activities have commenced on Phase 1 of Sakhalin I. Phase 1 facilities will include an offshore platform, onshore drill site for extended reach drilling to offshore oil zones, an onshore processing plant, an oil pipeline from Sakhalin Island to the Russian mainland and a mainland terminal for shipment of oil by tanker.

 

Thailand

 

ExxonMobil’s net onshore acreage totaled 21 thousand acres at year-end 2004. The total net well completions in 2004 were 0.2 development wells.

 

AFRICA

 

Angola

 

ExxonMobil’s year-end 2004 acreage holdings totaled 1.3 million net offshore acres and 7.7 net exploration and development wells were completed during the year. Production began at the ExxonMobil-operated Kizomba A development on Block 15 and construction is underway on the Kizomba B development. On the non-operated Block 17, construction is underway on the Dalia development, and engineering and design work is proceeding on the Rosa discovery.

 

Cameroon

 

ExxonMobil’s acreage totaled 0.3 million net offshore acres at year-end 2004, with 0.4 net development wells completed during the year.

 

Chad

 

ExxonMobil’s net year-end 2004 acreage holdings consisted of 3.3 million onshore acres, with 44.0 net exploration and development wells completed during the year. The Chad-Cameroon oil development and pipeline project reached full production in 2004, with start-up of the Kome and Bolobo fields.

 

Equatorial Guinea

 

ExxonMobil’s acreage totaled 0.5 million net offshore acres at year-end 2004, with 6.1 net development wells completed during the year.

 

Nigeria

 

ExxonMobil’s net acreage totaled 1.7 million offshore acres at year-end 2004, with 11.0 net exploration and development wells completed during the year. Drilling continued in 2004 on the new Yoho and Awawa platforms, installed in 2003, as development continued at the ExxonMobil-operated Yoho field (OML 104). The Yoho Floating, Storage and Offloading (FSO) facility also arrived on site and installation is progressing. Construction also continued on the Amenam-Kpono Phase 2 Gas project. Construction, installation and drilling activities continued at the Bonga field (OML 118), and

 

14


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Index to Financial Statements

drilling and construction activities are underway on the ExxonMobil-operated Erha field (OPL 209). Construction and installation are underway on the ExxonMobil-operated East Area Additional Oil Recovery project. The financing agreement and construction contracts for the ExxonMobil-operated East Area NGL project were signed in 2004.

 

OTHER COUNTRIES

 

Argentina

 

ExxonMobil’s net acreage totaled 0.3 million onshore acres at year-end 2004 and there were 0.5 net development wells completed during the year.

 

Venezuela

 

ExxonMobil’s net year-end 2004 acreage holdings totaled 0.2 million onshore acres, with 3.3 net development wells completed during the year.

 

Azerbaijan

 

At year-end 2004, ExxonMobil’s net acreage, located in the Caspian Sea offshore of Azerbaijan, totaled 0.1 million acres. During the year, 0.5 net exploration and development wells were completed. At the Azeri-Chirag-Gunashli (ACG) Early Oil project, oil production with pressure support from water injection is ongoing. Engineering and construction is underway on the first, second and third phases of full field development at ACG.

 

Kazakhstan

 

ExxonMobil’s net acreage totaled 0.2 million acres onshore and 0.2 million acres offshore at year-end 2004, with 4.0 net exploration and development wells completed during 2004. At Tengiz, construction of the 300 thousand barrels of oil per day (gross) expansion project began in 2003. Approval of the Kashagan field’s development plan by the Republic of Kazakhstan was received in February 2004. Detailed engineering of the initial phase of development is underway and the majority of the fabrication contracts have been placed.

 

Qatar

 

Production and development activities continued on natural gas projects in Qatar. Liquefied natural gas (LNG) operating companies include:

 

Qatar Liquefied Gas Company Limited — (QG)

Qatar Liquefied Gas Company Limited (II) — (QGII)

Ras Laffan Liquefied Gas Company Limited — (RL)

Ras Laffan Liquefied Gas Company Limited (II) — (RLII)

 

In addition, an ExxonMobil subsidiary is currently constructing natural gas production facilities for the Al Khaleej Gas (AKG) project to supply pipeline gas to domestic industrial customers.

 

At the end of 2004, 42 (gross) wells supplied natural gas to currently producing LNG facilities and drilling is underway to complete wells that will supply the new QGII, RLII and AKG projects.

 

Qatar LNG capacity volumes at year-end included 9.4 MTA (millions of metric tons per year) in QG trains 1-3 and a combined 11.3 MTA in RL trains 1-2 and RL II train 3. An expansion project is underway to increase the capacity of QG trains 1-3 to 9.7 MTA. Construction of QG II trains 4-5 will add planned capacity of 15.6 MTA when complete. In addition, construction of RL II trains 4-5 will add planned capacity of 9.4 MTA when complete.

 

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Index to Financial Statements

The conversion factor to translate Qatar LNG volumes (millions of metric tons - MT) into gas volumes (billions of cubic feet - BCF) is dependent on the gas quality and the quality of the LNG produced. The conversion factors are approximately 46 BCF/MT for QG trains 1-3, RL trains 1-2 and RLII train 3 and approximately 49 BCF/MT for QGII trains 4-5 and RLII trains 4-5.

 

Republic of Yemen

 

ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 0.9 million acres onshore at year-end 2004. During the year, 4.8 net development wells were completed.

 

United Arab Emirates

 

ExxonMobil’s net acreage in the Abu Dhabi onshore oil concession was 0.5 million acres at year-end 2004. During the year, 7.8 net exploratory and development wells were completed.

 

WORLDWIDE EXPLORATION

 

At year-end 2004, exploration activities were underway in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 35 million net acres were held at year-end 2004, and 1.2 net exploration wells were completed during the year in these countries.

 

Information with regard to mining activities follows:

 

Syncrude Operations

 

Syncrude is a joint-venture established to recover shallow deposits of tar sands using open-pit mining methods, to extract the crude bitumen, and to produce a high-quality, light (32 degree API), sweet, synthetic crude oil. The Syncrude operation, located near Fort McMurray, Alberta, Canada, exploits a portion of the Athabasca Oil Sands Deposit. The location is readily accessible by public road. The produced synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands Pipeline Ltd. Since start-up in 1978, Syncrude has produced about 1.5 billion barrels of synthetic crude oil. Imperial Oil Limited is the owner of a 25 percent interest in the joint-venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited.

 

Operating License and Leases

 

Syncrude has an operating license issued by the Province of Alberta which is effective until 2035. This license permits Syncrude to mine tar sands and produce synthetic crude oil from approved development areas on tar sands leases. Syncrude holds eight tar sands leases covering approximately 252,000 acres in the Athabasca Oil Sands Deposit which were issued by the Province of Alberta. The leases are automatically renewable as long as tar sands operations are ongoing or the leases are part of an approved development plan. Syncrude leases 10, 12, 17, 22 and 34 (containing proven reserves) and leases 29, 30 and 31 (containing no proven reserves) are included within a development plan approved by the Province of Alberta. There were no known previous commercial operations on these leases prior to the start-up of operations in 1978.

 

Operations, Plant and Equipment

 

Operations at Syncrude involve three main processes: open pit mining, extraction of crude bitumen and upgrading of crude bitumen into synthetic crude oil. In the Base mine (lease 17), the mining and transportation system uses draglines, bucketwheel reclaimers and belt conveyors. In the

 

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Index to Financial Statements

North mine (leases 17 and 22) and in the Aurora mine (leases 10, 12 and 34), truck, shovel and hydrotransport systems are used. Production from the Aurora mine commenced in 2000. The extraction facilities, which separates crude bitumen from sand, are capable of processing approximately 545,000 tons of tar sands a day, producing 110 million barrels of crude bitumen a year. This represents recovery capability of about 92 percent of the crude bitumen contained in the mined tar sands.

 

Crude bitumen extracted from tar sands is refined to a marketable hydrocarbon product through a combination of carbon removal in two large, high-temperature, fluid-coking vessels and by hydrogen addition in high-temperature, high-pressure, hydrocracking vessels. These processes remove carbon and sulfur and reformulate the crude into a low viscosity, low sulfur, high-quality synthetic crude oil product. In 2004, this upgrading process yielded 0.855 barrels of synthetic crude oil per barrel of crude bitumen. In 2004 about 46 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 54 percent was pipelined to refineries in eastern Canada and exported, primarily to the United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating plant and an 80 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. Imperial Oil Limited’s 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities was about $2.3 billion at year end 2004.

 

Synthetic Crude Oil Reserves

 

The crude bitumen is contained within the unconsolidated sands of the McMurray Formation. Ore bodies are buried beneath 50 to 150 feet of overburden, have bitumen grades ranging from 4 to 14 weight percent and ore thickness of 115 to 160 feet. Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The in-place volume, depth and grade are established through extensive and closely spaced core drilling. Proven reserves include the operating Base and North mines and the Aurora mine. In accordance with the approved mining plan, there are an estimated 2,055 million tons of extractable tar sands in the Base and North mines, with an average bitumen grade of 10.6 weight percent. In addition, at the Aurora mine, there are an estimated 4,470 million tons of extractable tar sands at an average bitumen grade of 11.1 weight percent. After deducting royalties payable to the Province of Alberta, Imperial Oil Limited estimates that its 25 percent net share of proven reserves at year end 2004 was equivalent to 757 million barrels of synthetic crude oil.

 

In 2001, the Syncrude owners endorsed a further development of the Syncrude resource in the area and expansion of the upgrading facilities. The Syncrude Aurora 2 and Upgrader Expansion 1 project adds a remote mining train and expands the central processing and upgrading plant. This expansion is under way and will lead to total production of about 350 thousand barrels of synthetic crude oil per day (gross) when completed.

 

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Index to Financial Statements

ExxonMobil Share of Net Proven Syncrude Reserves(1)

 

     Synthetic Crude Oil

 
     Base Mine and
North Mine


    Aurora Mine

    Total

 
     (millions of barrels)  

January 1, 2004

   331     450     781  

Revision of previous estimate

   (103 )   100     (3 )

Production

   (11 )   (10 )   (21 )
    

 

 

December 31, 2004

   217     540     757  
    

 

 


(1)   Net reserves are the company’s share of reserves after deducting royalties payable to the Province of Alberta.

 

Syncrude Operating Statistics (total operation)

 

     2004

   2003

   2002

    2001

    2000

 

Operating Statistics

                            

Total mined volume (millions of cubic yards)(1)

   100.3    109.2    102.0     118.3     85.1  

Mined volume to tar sands ratio(1)

   0.94    1.15    1.05     1.15     0.96  

Tar sands mined (millions of tons)

   188.0    168.0    172.1     181.2     156.4  

Average bitumen grade (weight percent)

   11.1    11.0    11.2     11.0     11.0  
    
  
  

 

 

Crude bitumen in mined tar sands (millions of tons)

   20.9    18.5    19.2     19.9     17.2  

Average extraction recovery (percent)

   87.3    88.6    89.9     87.0     89.7  
    
  
  

 

 

Crude bitumen production (millions of barrels)(2)

   103.3    92.3    97.8     97.6     86.8  

Average upgrading yield (percent)

   85.5    86.0    86.3     84.5     84.3  
    
  
  

 

 

Gross synthetic crude oil produced (millions of barrels)

   88.4    78.4    84.8     82.4     73.2  

ExxonMobil net share (millions of barrels)(3)

   22    19    21     19     15  

(1)   Includes pre-stripping of mine areas and reclamation volumes.
(2)   Crude bitumen production is equal to crude bitumen in mined tar sands multiplied by the average extraction recovery and the appropriate conversion factor.
(3)   Reflects ExxonMobil’s 25 percent interest in production less applicable royalties payable to the Province of Alberta.

 

Item 3.    Legal Proceedings.

 

On November 30, 2004, the New York State Department of Environmental Conservation (“NYSDEC”) proposed a statewide settlement of petroleum bulk storage compliance issues at all active petroleum bulk storage sites in New York, and any investigation and remediation required at those sites. The proposal includes requirements that the company perform a compliance audit at each site, undertake a $1.5 million environmental benefit project, pay a penalty of $5 million, and pay oversight costs. ExxonMobil is evaluating the offer and will respond to the NYSDEC. No formal action has been taken by the NYSDEC regarding these matters.

 

Refer to the relevant portions of note 16 beginning on page 70 of the Financial Section of this report for additional information on legal proceedings.

 

Item 4.    Submission of Matters to a Vote of Security Holders.

 

None.

 


 

18


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Index to Financial Statements

Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)].

 

Name


  Age as of
March 16,
2005


  Title (Held Office Since)

L. R. Raymond

  66   Chairman of the Board (1993)

R. W. Tillerson

  52   President (2004)

E. G. Galante

  54   Senior Vice President (2001)

S. R. McGill

  62   Senior Vice President (2004)

J. S. Simon

  61   Senior Vice President (2004)

M. W. Albers

  48   President, ExxonMobil Development Company (2004)

A. T. Cejka

  53   Vice President (2004)

H. R. Cramer

  54   Vice President (1999)

P. J. Dingle

  56   Vice President (2003)

M. J. Dolan

  51   Vice President (2004)

M. E. Foster

  61   Vice President (2004)

H. H. Hubble

  52   Vice President—Investor Relations and Secretary (2004)

D. D. Humphreys

  57   Vice President and Treasurer (2004)

G. L. Kohlenberger

  52   Vice President (2002)

C. W. Matthews

  60   Vice President and General Counsel (1995)

P. T. Mulva

  53   Vice President and Controller (2004)

S. D. Pryor

  55   Vice President (2004)

P. E. Sullivan

  61   Vice President and General Tax Counsel (1995)

 

For at least the past five years, Messrs. Cramer, Humphreys, Matthews, McGill, Raymond, Simon and Sullivan have been employed as executives of the registrant. Mr. Tillerson was a Senior Vice President before becoming President. Mr. McGill was President of ExxonMobil Production Company before becoming Senior Vice President. Mr. Simon was President of ExxonMobil Refining & Supply Company before becoming Senior Vice President. Mr. Humphreys was Vice President and Controller before becoming Vice President and Treasurer. Mr. Mulva was Vice President—Investor Relations and Secretary before becoming Vice President and Controller.

 

The following executive officers of the registrant have also served as executives of the subsidiaries, affiliates or divisions of the registrant shown opposite their names during the five years preceding December 31, 2004.

 

Esso Exploration and Production Chad Inc.

   Albers

Esso Malaysia Berhad

   Dingle

Esso Production Malaysia Inc.

   Dingle

Exxon Neftegas Limited

   Tillerson

Exxon Ventures (CIS) Inc. 

   Tillerson

ExxonMobil Chemical Company

   Dolan, Galante and Pryor

ExxonMobil Development Company

   Albers, Foster and Tillerson

ExxonMobil Exploration Company

   Cejka

ExxonMobil Fuels Marketing Company

   Cramer

ExxonMobil Gas & Power Marketing Company

   Dingle

ExxonMobil Global Services Company

   Kohlenberger

ExxonMobil Lubricants & Petroleum Specialties Company

   Kohlenberger and Pryor

ExxonMobil Production Company

   Albers and Foster

ExxonMobil Refining & Supply Company

   Dolan, Hubble and Pryor

Imperial Oil Limited

   Mulva

Mobil Business Resources Corporation

   Kohlenberger

 

Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such officer serving until a successor has been elected and qualified.

 

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Index to Financial Statements

PART II

 

Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities.

 

Reference is made to the quarterly information which appears on page 88 of the Financial Section of this report.

 

Issuer Purchase of Equity Securities for Quarter Ended December 31, 2004


 

Period


   Total Number of
Shares
Purchased


   Average Price
Paid per
Share


   Total Number of
Shares
Purchased as
Part of Publicly
Announced
Plans or
Programs


   Maximum Number
of Shares that
May Yet Be
Purchased Under
the Plans or
Programs


 

October, 2004

   19,224,883    $ 49.10    19,224,883       

November, 2004

   18,984,573    $ 50.11    18,984,573       

December, 2004

   22,617,237    $ 50.67    22,617,237       
    
         
      

Total

   60,826,693    $ 50.00    60,826,693    (See note 1 )

 

Note 1—On August 1, 2000, the Corporation announced its intention to resume purchases of shares of its common stock for the treasury both to offset shares issued in conjunction with company benefit plans and programs and to gradually reduce the number of shares outstanding. The announcement did not specify an amount or expiration date. The Corporation has continued to purchase shares since this announcement and to report purchased volumes in its quarterly earnings releases. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.

 

20


Table of Contents
Index to Financial Statements

Item 6.    Selected Financial Data.

 

    Years Ended December 31,

    2004

    2003  

    2002  

  2001

  2000

    (millions of dollars, except per share amounts)

Sales and other operating revenue(1)

  $ 291,252   $ 237,054   $ 200,949   $ 208,715   $ 227,596

(1) Excise taxes included

  $ 27,263   $ 23,855   $ 22,040   $ 21,907   $ 22,356

Net income

                             

Income from continuing operations

  $ 25,330   $ 20,960   $ 11,011   $ 15,003   $ 15,806

Discontinued operations, net of income tax

            449     102     184

Extraordinary gain, net of income tax

                215     1,730

Cumulative effect of accounting change, net of income tax

        550            
   

 

 

 

 

Net income

  $ 25,330   $ 21,510   $ 11,460   $ 15,320   $ 17,720

Net income per common share

                             

Income from continuing operations

  $ 3.91   $ 3.16   $ 1.62   $ 2.19   $ 2.27

Discontinued operations, net of income tax

            0.07     0.01     0.03

Extraordinary gain, net of income tax

                0.03     0.25

Cumulative effect of accounting change, net of income tax

        0.08            
   

 

 

 

 

Net income

  $ 3.91   $ 3.24   $ 1.69   $ 2.23   $ 2.55

Net income per common share - assuming dilution

                             

Income from continuing operations

  $ 3.89   $ 3.15   $ 1.61   $ 2.17   $ 2.24

Discontinued operations, net of income tax

            0.07     0.01     0.03

Extraordinary gain, net of income tax

                0.03     0.25

Cumulative effect of accounting change, net of income tax

        0.08            
   

 

 

 

 

Net income

  $ 3.89   $ 3.23   $ 1.68   $ 2.21   $ 2.52
Cash dividends per common share   $ 1.06   $ 0.98   $ 0.92   $ 0.91   $ 0.88
Total assets   $ 195,256   $ 174,278   $ 152,644   $ 143,174   $ 149,000
Long-term debt   $ 5,013   $ 4,756   $ 6,655   $ 7,099   $ 7,280

 

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

 

Reference is made to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 30 of the Financial Section of this report.

 

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk.

 

Reference is made to the section entitled “Market Risks, Inflation and Other Uncertainties” beginning on page 39, excluding the part entitled “Inflation and Other Uncertainties,” of the Financial Section of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.

 

21


Table of Contents
Index to Financial Statements

Item 8.    Financial Statements and Supplementary Data.

 

Reference is made to the following in the Financial Section of this report:

 

    Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 28, 2005, beginning on page 48 with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing to page 77;
    Quarterly Information (unaudited) appearing on page 88;
    Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited) appearing on pages 78 through 87; and
    Frequently Used Terms (unaudited) on pages 28 and 29.

 

Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.

 

Item  9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.                      

 

None.

 

Item  9A.    Controls and Procedures.

 

Management’s Evaluation of Disclosure Controls and Procedures

 

As indicated in the certifications in Exhibit 31 of this report, the Corporation’s chief executive officer, principal accounting officer and principal financial officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2004. Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that material information required to be in this annual report is made known to them on a timely basis.

 

Management’s Report on Internal Control over Financial Reporting

 

Management, including the Corporation’s chief executive officer, principal accounting officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of 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 this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2004.

 

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2004, was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report beginning on page 48 of the Financial Section of this report.

 

Changes in Internal Control over Financial Reporting

 

There were no changes during the Corporation’s last fiscal quarter that materially affected, or are reasonably likely to materially affect the Corporation’s internal control over financial reporting.

 

Item  9B.    Other Information.

 

None.

 

22


Table of Contents
Index to Financial Statements

PART III

 

Item 10.    Directors and Executive Officers of the Registrant.

 

Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2005 annual meeting of shareholders (the “2005 Proxy Statement”):

 

    The section entitled “Election of Directors”;
    The portion entitled “Section 16(a) Beneficial Ownership Reporting Compliance” of the section entitled “Executive Compensation Tables”;
    The portion entitled “Code of Ethics and Business Conduct” of the section entitled “Corporate Governance Guidelines”; and
    The “Audit Committee” portion and the membership table of the section entitled “Board Committees”.

 

Item 11.    Executive Compensation.

 

Incorporated by reference to the section entitled “Director Compensation” and the section entitled “Executive Compensation Tables” of the registrant’s 2005 Proxy Statement.

 

Item 12.    Security Ownership of Certain Beneficial Owners and Management.

 

Incorporated by reference to the section entitled “Director and Executive Officer Stock Ownership” and the portion entitled “Equity Compensation Plan Information” of the section entitled “Executive Compensation Tables” of the registrant’s 2005 Proxy Statement.

 

Item 13.    Certain Relationships and Related Transactions.

 

Incorporated by reference to the portion entitled “Director Relationships” of the section entitled “Election of Directors” of the registrant’s 2005 Proxy Statement.

 

Item 14.    Principal Accounting Fees and Services.

 

Incorporated by reference to the section entitled “Ratification of Independent Auditors” of the registrant’s 2005 Proxy Statement.

 

PART IV

 

Item 15.    Exhibits, Financial Statement Schedules.

 

  (a) (1) and (2) Financial Statements:

See Table of Contents on page 25 of the Financial Section of this report.

 

  (a) (3) Exhibits:

See Index to Exhibits beginning on page 92 of this report.

 

23


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Index to Financial Statements

 

 

[THIS PAGE INTENTIONALLY LEFT BLANK]

 

 

 

24


Table of Contents
Index to Financial Statements

 

FINANCIAL SECTION

 

TABLE OF CONTENTS

 

Business Profile

   26

Financial Summary

   27

Frequently Used Terms

   28

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

    

Functional Earnings

   30

Forward-Looking Statements

   31

Overview

   31

Business Environment and Outlook

   31

Review of 2004 and 2003 Results

   32

Liquidity and Capital Resources

   34

Capital and Exploration Expenditures

   38

Taxes

   38

Merger Expenses and Reorganization Reserves

   38

Asset Retirement Obligations and Environmental Costs

   39

Market Risks, Inflation and Other Uncertainties

   39

Recently Issued Statements of Financial Accounting Standards

   40

Emerging Accounting and Reporting Issues

   41

Critical Accounting Policies

   41

Management’s Report on Internal Control Over Financial Reporting

   48

Report of Independent Registered Public Accounting Firm

   48

Consolidated Financial Statements

    

Statement of Income

   50

Balance Sheet

   51

Statement of Shareholders’ Equity

   52

Statement of Cash Flows

   53

Notes to Consolidated Financial Statements

    

  1. Summary of Accounting Policies

   54

  2. Discontinued Operations

   56

  3. Merger Expenses and Reorganization Reserves

   56

  4. Miscellaneous Financial Information

   57

  5. Cash Flow Information

   57

  6. Additional Working Capital Information

   57

  7. Equity Company Information

   58

  8. Investments and Advances

   59

  9. Property, Plant and Equipment and Asset Retirement Obligations

   59

10. Leased Facilities

   61

11. Employee Stock Ownership Plans

   61

12. Capital

   62

13. Financial Instruments and Derivatives

   63

14. Long-Term Debt

   63

15. Incentive Program

   68

16. Litigation and Other Contingencies

   70

17. Annuity Benefits and Other Postretirement Benefits

   72

18. Disclosures about Segments and Related Information

   75

19. Income, Excise and Other Taxes

   77

Supplemental Information on Oil and Gas Exploration and Production Activities

   78

Quarterly Information

   88

Operating Summary

   89

 

25


Table of Contents
Index to Financial Statements

BUSINESS PROFILE

 

     Earnings After
Income Taxes


   Average Capital
Employed


   Return on
Average
Capital
Employed


   Capital and
Exploration
Expenditures


Financial


   2004

    2003

   2004

   2003

   2004

   2003

   2004

   2003

     (millions of dollars)    (percent)    (millions of dollars)

Upstream

                                                    

United States

   $ 4,948     $ 3,905    $ 13,355    $ 13,508    37.0    28.9    $ 1,922    $ 2,125

Non-U.S.

     11,727       10,597      37,287      34,164    31.5    31.0      9,793      9,863
    


 

  

  

            

  

Total

   $ 16,675     $ 14,502    $ 50,642    $ 47,672    32.9    30.4    $ 11,715    $ 11,988
    


 

  

  

            

  

Downstream

                                                    

United States

   $ 2,186     $ 1,348    $ 7,632    $ 8,090    28.6    16.7    $ 775    $ 1,244

Non-U.S.

     3,520       2,168      19,541      18,875    18.0    11.5      1,630      1,537
    


 

  

  

            

  

Total

   $ 5,706     $ 3,516    $ 27,173    $ 26,965    21.0    13.0    $ 2,405    $ 2,781
    


 

  

  

            

  

Chemical

                                                    

United States

   $ 1,020     $ 381    $ 5,246    $ 5,194    19.4    7.3    $ 262    $ 333

Non-U.S.

     2,408       1,051      9,362      8,905    25.7    11.8      428      359
    


 

  

  

            

  

Total

   $ 3,428     $ 1,432    $ 14,608    $ 14,099    23.5    10.2    $ 690    $ 692
    


 

  

  

            

  

Corporate and financing

     (479 )     1,510      14,916      6,637    —      —        75      64

Accounting change

     —         550      —        —      —      —                
    


 

  

  

            

  

Total

   $ 25,330     $ 21,510    $ 107,339    $ 95,373    23.8    20.9    $ 14,885    $ 15,525
    


 

  

  

            

  

 

See Frequently Used Terms on pages 28 and 29 for a definition and calculation of capital employed and return on average capital employed.

 

Operating


   2004

   2003

     (thousands of barrels daily)

Net liquids production

         

United States

   557    610

Non-U.S.

   2,014    1,906
    
  

Total

   2,571    2,516
     (millions of cubic feet daily)

Natural gas production available for sale

         

United States

   1,947    2,246

Non-U.S.

   7,917    7,873
    
  

Total

   9,864    10,119
     (thousands of oil-equivalent
barrels daily)

Oil-equivalent production (1)

   4,215    4,203

 

(1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.

 

     2004

   2003

     (thousands of barrels daily)

Petroleum product sales

         

United States

   2,872    2,729

Non-U.S.

   5,338    5,228
    
  

Total

   8,210    7,957
     (thousands of barrels daily)

Refinery throughput

         

United States

   1,850    1,806

Non-U.S.

   3,863    3,704
    
  

Total

   5,713    5,510
     (thousands of metric tons)

Chemical prime product sales

         

United States

   11,521    10,740

Non-U.S.

   16,267    15,827
    
  

Total

   27,788    26,567

 

26


Table of Contents
Index to Financial Statements

FINANCIAL SUMMARY

 

     2004

    2003

    2002

    2001

    2000

 
     (millions of dollars, except per share amounts)  

Sales and other operating revenue (1)

                                        

Upstream

   $ 23,033     $ 21,330     $ 16,484     $ 18,567     $ 21,509  

Downstream

     240,413       195,511       168,032       174,185       188,563  

Chemical

     27,781       20,190       16,408       15,943       17,501  

Other

     25       23       25       20       23  
    


 


 


 


 


Total

   $ 291,252     $ 237,054     $ 200,949     $ 208,715     $ 227,596  
    


 


 


 


 


Earnings

                                        

Upstream

   $ 16,675     $ 14,502     $ 9,598     $ 10,736     $ 12,685  

Downstream

     5,706       3,516       1,300       4,227       3,418  

Chemical

     3,428       1,432       830       707       1,161  

Corporate and financing

     (479 )     1,510       (442 )     (142 )     (538 )

Merger-related expenses

     —         —         (275 )     (525 )     (920 )
    


 


 


 


 


Income from continuing operations

   $ 25,330     $ 20,960     $ 11,011     $ 15,003     $ 15,806  

Discontinued operations

     —         —         449       102       184  

Extraordinary gain

     —         —         —         215       1,730  

Accounting change

     —         550       —         —         —    
    


 


 


 


 


Net income

   $ 25,330     $ 21,510     $ 11,460     $ 15,320     $ 17,720  
    


 


 


 


 


Net income per common share

   $ 3.91     $ 3.24     $ 1.69     $ 2.23     $ 2.55  

Net income per common share – assuming dilution

   $ 3.89     $ 3.23     $ 1.68     $ 2.21     $ 2.52  

Cash dividends per common share

   $ 1.06     $ 0.98     $ 0.92     $ 0.91     $ 0.88  

Net income to average shareholders’ equity (percent)

     26.4       26.2       15.5       21.3       26.4  

Working capital

   $ 17,396     $ 7,574     $ 5,116     $ 5,567     $ 2,208  

Ratio of current assets to current liabilities

     1.40       1.20       1.15       1.18       1.06  

Additions to property, plant and equipment

   $ 11,986     $ 12,859     $ 11,437     $ 9,989     $ 8,446  

Property, plant and equipment, less allowances

   $ 108,639     $ 104,965     $ 94,940     $ 89,602     $ 89,829  

Total assets

   $ 195,256     $ 174,278     $ 152,644     $ 143,174     $ 149,000  

Exploration expenses, including dry holes

   $ 1,098     $ 1,010     $ 920     $ 1,175     $ 936  

Research and development costs

   $ 649     $ 618     $ 631     $ 603     $ 564  

Long-term debt

   $ 5,013     $ 4,756     $ 6,655     $ 7,099     $ 7,280  

Total debt

   $ 8,293     $ 9,545     $ 10,748     $ 10,802     $ 13,441  

Fixed-charge coverage ratio (times)

     36.1       30.8       13.8       17.7       15.6  

Debt to capital (percent)

     7.3       9.3       12.2       12.4       15.4  

Net debt to capital (percent) (2)

     (10.7 )     (1.2 )     4.4       5.3       7.9  

Shareholders’ equity at year end

   $ 101,756     $ 89,915     $ 74,597     $ 73,161     $ 70,757  

Shareholders’ equity per common share

   $ 15.90     $ 13.69     $ 11.13     $ 10.74     $ 10.21  

Weighted average number of common shares outstanding (millions)

     6,482       6,634       6,753       6,868       6,953  

Number of regular employees at year end (thousands) (3)

     85.9       88.3       92.5       97.9       99.6  

CORS employees not included above (thousands) (4)

     19.3       17.4       16.8       19.9       18.7  

 

(1) Sales and other operating revenue includes excise taxes of $27,263 million for 2004, $23,855 million for 2003, $22,040 million for 2002, $21,907 million for 2001 and $22,356 million for 2000.

 

(2) Debt net of cash, excluding restricted cash. The ratio of net debt to capital including restricted cash is (16.3) percent for 2004.

 

(3) Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs.

 

(4) CORS employees are employees of company-operated retail sites.

 

27


Table of Contents
Index to Financial Statements

FREQUENTLY USED TERMS

 

Listed below are definitions of several of ExxonMobil’s key business financial performance measures. These definitions are provided to facilitate understanding of the terms and their calculation.

 

CASH FLOW FROM OPERATIONS AND ASSET SALES

 

Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds from sales of subsidiaries, investments and property, plant and equipment from the Consolidated Statement of Cash Flows. This cash flow is the total sources of cash from both operating the Corporation’s assets and from the divesting of assets. The Corporation employs a long-standing disciplined regular review process to ensure that all assets are contributing to the Corporation’s strategic and financial objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.

 

Cash flow from operations and asset sales


   2004

   2003

   2002

     (millions of dollars)

Net cash provided by operating activities

   $ 40,551    $ 28,498    $ 21,268

Sales of subsidiaries, investments and property, plant and equipment

     2,754      2,290      2,793
    

  

  

Cash flow from operations and asset sales

   $ 43,305    $ 30,788    $ 24,061
    

  

  

 

CAPITAL EMPLOYED

 

Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it includes ExxonMobil’s net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the Corporation, it includes ExxonMobil’s share of total debt and shareholders’ equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed.

 

Capital employed


   2004

    2003

    2002

 
     (millions of dollars)  

Business uses: asset and liability perspective

                        

Total assets

   $ 195,256     $ 174,278     $ 152,644  

Less liabilities and minority share of assets and liabilities

                        

Total current liabilities excluding notes and loans payable

     (39,701 )     (33,597 )     (29,082 )

Total long-term liabilities excluding long-term debt and equity of minority and preferred shareholders in affiliated companies

     (41,554 )     (37,839 )     (35,449 )

Minority share of assets and liabilities

     (5,285 )     (4,945 )     (4,210 )

Add ExxonMobil share of debt-financed equity company net assets

     3,914       4,151       4,795  
    


 


 


Total capital employed

   $ 112,630     $ 102,048     $ 88,698  
    


 


 


Total corporate sources: debt and equity perspective

                        

Notes and loans payable

   $ 3,280     $ 4,789     $ 4,093  

Long-term debt

     5,013       4,756       6,655  

Shareholders’ equity

     101,756       89,915       74,597  

Less minority share of total debt

     (1,333 )     (1,563 )     (1,442 )

Add ExxonMobil share of equity company debt

     3,914       4,151       4,795  
    


 


 


Total capital employed

   $ 112,630     $ 102,048     $ 88,698  
    


 


 


 

28


Table of Contents
Index to Financial Statements

RETURN ON AVERAGE CAPITAL EMPLOYED

 

Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporation’s total ROCE is net income excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in our capital-intensive, long-term industry, both to evaluate management’s performance and to demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which tend to be more cash flow based, are used for future investment decisions.

 

Return on average capital employed


   2004

    2003

    2002

 
     (millions of dollars)  

Net income

   $ 25,330     $ 21,510     $ 11,460  

Financing costs (after tax)

                        

Third-party debt

     (137 )     (69 )     (81 )

ExxonMobil share of equity companies

     (185 )     (172 )     (227 )

All other financing costs – net (1)

     54       1,775       (127 )
    


 


 


Total financing costs

     (268 )     1,534       (435 )
    


 


 


Earnings excluding financing costs

   $ 25,598     $ 19,976     $ 11,895  
    


 


 


Average capital employed

   $ 107,339     $ 95,373     $ 88,342  

Return on average capital employed – corporate total

     23.8 %     20.9 %     13.5 %

 

(1) “All other financing costs – net” in 2003 includes interest income (after tax) associated with the settlement of a U.S. tax dispute.

 

29


Table of Contents
Index to Financial Statements

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

FUNCTIONAL EARNINGS


   2004

    2003

   2002

 
     (millions of dollars, except per share amounts)  

Net income (U.S. GAAP)

                       

Upstream

                       

United States

   $ 4,948     $ 3,905    $ 2,524  

Non-U.S.

     11,727       10,597      7,074  

Downstream

                       

United States

     2,186       1,348      693  

Non-U.S.

     3,520       2,168      607  

Chemical

                       

United States

     1,020       381      384  

Non-U.S.

     2,408       1,051      446  

Corporate and financing

     (479 )     1,510      (442 )

Merger-related expenses

     —         —        (275 )
    


 

  


Income from continuing operations

   $ 25,330     $ 20,960    $ 11,011  

Discontinued operations

     —         —        449  

Accounting change

     —         550      —    
    


 

  


Net income

   $ 25,330     $ 21,510    $ 11,460  
    


 

  


Net income per common share

   $ 3.91     $ 3.24    $ 1.69  

Net income per common share – assuming dilution

   $ 3.89     $ 3.23    $ 1.68  

Special items included in net income

                       

Non-U.S. Upstream

                       

Gain on transfer of Ruhrgas shares

   $ —       $ 1,700    $ —    

U.K. deferred income tax adjustment

   $ —       $ —      $ (215 )

U.S. Downstream

                       

Allapattah lawsuit provision

   $ (550 )   $ —      $ —    

Corporate and financing

                       

U.S. tax settlement

   $ —       $ 2,230    $ —    

 

30


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Index to Financial Statements

FORWARD-LOOKING STATEMENTS

 

Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including production growth; financing sources; the resolution of contingencies; the effect of changes in prices; interest rates and other market conditions; and environmental and capital expenditures could differ materially depending on a number of factors, such as the outcome of commercial negotiations; changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; and other factors discussed herein and under the caption “Factors Affecting Future Results” in Item 1 of ExxonMobil’s 2004 Form 10-K.

 

OVERVIEW

 

The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The Corporation’s business model involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods.

 

This straightforward approach extends to the financing of the business. In evaluating business or investment opportunities, the Corporation views as economically equivalent any debt obligation, whether included on the face of the consolidated balance sheet, or disclosed as other debt-like obligations in notes to the financial statements, such as ExxonMobil’s share of equity company debt and noncancelable, long-term operating leases. This consistent, conservative approach to financing the capital-intensive needs of the Corporation has helped ExxonMobil to sustain the “triple-A” status of its long-term debt securities for 86 years.

 

ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well positioned to participate in substantial investments to develop new energy supplies. While commodity prices remain volatile on a short-term basis depending on supply and demand, ExxonMobil’s investment decisions are based on our long-term outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and used for investment evaluation purposes. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects. ExxonMobil views return on capital employed as the best measure of historical capital productivity.

 

BUSINESS ENVIRONMENT AND OUTLOOK

 

Upstream

 

The Corporation expects worldwide economic growth to average just under 3 percent per year through 2030. This growth, and rising personal incomes notably in developing nations, should increase global energy demand by 1.7 percent per year, reaching 50 percent more than today by 2030. Oil, natural gas and coal are expected to remain the predominant fuels through the middle of the century. The share of oil and gas in the world’s energy supply, close to 60 percent today, should remain relatively stable, and total fossil fuels, including coal, will account for about 80 percent of the energy mix. In the very long term, the energy mix will likely become more diversified. However, for the foreseeable future, fossil fuels are the only energy forms with the scale and versatility to meet the challenge of growing world energy demand.

 

Oil demand should grow at 1.5 percent per year, with increasing use of oil in the transportation sector. However, natural gas is expected to be the fastest-growing primary energy source, capturing about 30 percent of the growth in total energy demand, and reaching one quarter of the total energy supply. About half of the growth in gas demand will likely be to meet worldwide electricity demand that is expected to double by 2030. The Corporation expects the liquefied natural gas (LNG) market to quadruple, helping to meet rising import dependency in Europe, North America and Asia. With equity positions in many of the largest remote gas accumulations in the world, the Corporation is positioned to benefit from its technology advances in gas liquefaction, transportation and regasification that enable distant gas supplies to reach markets economically.

 

On average, the world’s oil and gas fields are declining in production at between 4 percent and 6 percent per year. While large resources exist, technology advances remain critical to increasing future oil and gas supplies. Emerging technologies promise to further advance our capability to extend recoverable resources worldwide. The cost to develop these resources is also very large. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide through 2030 will be about $200 billion per year.

 

ExxonMobil maintains the largest portfolio of exploration and development opportunities among the international oil companies, which enables the selectivity required to optimize total profitability and mitigate overall political and technical risks. As future development projects bring new resources on line, the Corporation expects a shift in the geographic mix of production volumes between now and 2010. For example, oil and natural gas output from West Africa, the Caspian, the Middle East and Russia will more than double during the next six years based on current capital project execution plans. Currently, these growth areas account for less than 20 percent of the Corporation’s production. By the end of the decade, they are expected to generate about 40 percent of total volumes. Production from established areas, including Europe and North America, will decline as a percentage of the Corporation’s total production but still is expected to represent over half of 2010 volumes.

 

In addition to a changing geographic mix, there will also be a change in the type of opportunities from which volumes are produced. Production using arctic technology, deepwater drilling and production systems, heavy oil recovery processes and LNG is expected to grow from 20 percent to 40 percent of the Corporation’s output between now and 2010. The Corporation’s overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity

 

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Index to Financial Statements

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

increases to average 3 percent annually through 2010. However, actual volume increases will vary from year to year due to timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, price effects on production sharing contracts and other factors described under the caption “Factors Affecting Future Results” in Item 1 of ExxonMobil’s 2004 Form l0-K.

 

Restructuring of our European gas marketing operations has progressed in anticipation of the impact of the European Gas Directives. Part of this effort includes a Heads of Agreement (HOA) whereby Esso Nederland B.V. and Shell Nederland B.V. will agree to transfer their ownership share of 25 percent each in Gasunie’s gas transportation business to the State of the Netherlands. As specified in the HOA, the State of the Netherlands will pay a total net compensation in the amount of 2.78 billion Euros to the Dutch company Nederlandse Aardolie Maatschappij B.V., jointly owned by ExxonMobil and Shell. The parties intend to finalize the restructuring by mid-2005, and it is anticipated that, at that time, this step will have a positive impact on the Corporation’s results. The restructuring will position ExxonMobil to compete effectively in the future European gas market and enable us to directly sell more of our equity production.

 

Downstream

 

The downstream industry environment remains very competitive. Long-term real refining margins have historically declined at a rate of about 2 percent per year and the intense competition in the retail fuels market has driven long-term real margins down by 4 percent per year. The outlook is for modest industry growth in mature markets with increasing requirements for regulatory investments.

 

Refining margins are a function of the difference between what a refinery pays for its raw materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating oil, jet fuel and fuel oil). Crude oil and many products are widely traded with published prices, including those quoted on multiple exchanges around the world (e.g., New York Mercantile Exchange and International Petroleum Exchange). Prices for these commodities (crude and various products) are determined by the global marketplace and are impacted by many industry factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, seasonality and weather. These prices and factors are continuously monitored and serve as input to decisions about which raw materials to buy, facilities to operate and products to make. However, there are no reliable indicators of future market factors that accurately predict changes in margins from period to period.

 

The objectives of ExxonMobil’s Downstream strategies are to position the Corporation to be the industry leader and outperform competition under a variety of market conditions. These strategies include maintaining best-in-class operations in all respects, maximizing value from leading-edge technology, capitalizing on integration with other ExxonMobil businesses and providing quality, valued products and services to the Corporation’s customers. ExxonMobil has an ownership interest in 45 refineries, located in 25 countries, with distillation capacity of 6.4 million barrels per day and lubricant basestock manufacturing capacity of about 145 thousand barrels per day. ExxonMobil’s fuels marketing business portfolio includes operations in over 100 countries on six continents, serving a globally diverse customer base. World-class scale and integration, industry-leading efficiency, leading-edge technology and globally respected brands enable ExxonMobil to take advantage of attractive emerging-growth opportunities around the globe. For example, our assets are well-positioned and configured to supply demand growth in Asia Pacific, which we estimate will be 3 percent annually through 2020.

 

Chemical

 

The strength of the global economy supported strong demand growth for petrochemical products in 2004. Demand growth in Asia benefited from continued economic and industrial production growth, and the North American market recovered from weak conditions in 2003. Growth in Europe was moderate, consistent with the less favorable economic environment. As a result of strong demand growth and limited new capacity additions, regional and global supply demand balances tightened, supporting higher prices and margins despite increased feedstock costs. ExxonMobil’s portfolio includes many of the largest-volume and highest-growth petrochemicals in the global economy. In addition to being a worldwide supplier of primary petrochemical products, the Corporation also has a diverse portfolio of less cyclical business lines. The Corporation’s competitive advantages are achieved through its business mix, investment discipline, integration of chemical capacity with large refining complexes or upstream gas processing, operational excellence, including leading proprietary technology, and product application expertise.

 

REVIEW OF 2004 AND 2003 RESULTS

 

     2004

   2003

   2002

     (millions of dollars)

Income from continuing operations

   $ 25,330    $ 20,960    $ 11,011

Discontinued operations

     —        —        449

Accounting change

     —        550      —  
    

  

  

Net income (U.S. GAAP)

   $ 25,330    $ 21,510    $ 11,460
    

  

  

 

2004

 

Net income in 2004 of $25,330 million was the highest ever for the Corporation, up $3,820 million from 2003. Net income in 2004 included a one-time special charge of $550 million relating to the Allapattah lawsuit provision. Interest expense in 2004 increased to $638 million compared to $207 million in 2003, reflecting the interest component of the Allapattah lawsuit provision.

 

Total assets at December 31, 2004, of $195 billion increased by approximately $21 billion from 2003, reflecting strong earnings and the Corporation’s active investment program, particularly in the Upstream.

 

2003

 

Net income in 2003 was $21,510 million, an increase of $10,050 million from 2002. Excluding a $550 million positive impact for the required adoption of Statement of Financial Accounting Standards No. 143 (FAS 143) relating to accounting for asset retirement obligations, income from continuing operations was $20,960 million. 2003 net income also included one-time special items of $2,230 million relating to the positive settlement of a long-running U.S. tax dispute and $1,700 million from a gain on the transfer of shares in Ruhrgas AG, a German gas transmission company. Interest expense in 2003 was $207 million compared to $398 million in 2002, reflecting lower debt levels and nondebt-related items.

 

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Index to Financial Statements

Total assets at December 31, 2003, of $174 billion increased by approximately $22 billion from 2002, reflecting the Corporation’s active investment program and the effect of the weaker U.S. dollar.

 

Upstream

 

     2004

   2003

   2002

     (millions of dollars)

Upstream

                    

United States

   $ 4,948    $ 3,905    $ 2,524

Non-U.S.

     11,727      10,597      7,074
    

  

  

Total

   $ 16,675    $ 14,502    $ 9,598
    

  

  

 

2004

 

Upstream earnings of $16,675 million increased $2,173 million due to higher liquids and natural gas realizations. Upstream earnings for 2003 included a $1,700 million special item from a gain on the transfer of shares in Ruhrgas AG. Absent this, Upstream earnings increased $3,873 million in 2004. Oil-equivalent production was up 3 percent versus 2003 excluding price-related entitlement effects and divestment impacts. Including these impacts, total oil-equivalent production was flat with 2003. Liquids production of 2,571 Kbd (thousands of barrels daily) increased 55 Kbd from 2003. Production increases in West Africa and Norway were partly offset by natural field decline in mature areas, entitlement effects and divestment impacts. Natural gas production of 9,864 mcfd (millions of cubic feet daily) in 2004 compared with 10,119 mcfd in 2003. The start-up of an additional LNG train in Qatar and contributions from projects and work programs were more than offset by natural field decline, divestment impacts and entitlement effects. Earnings from U.S. Upstream operations for 2004 of $4,948 million were $1,043 million higher than 2003 due to higher realizations partly offset by lower production volumes. Earnings outside the U.S. for 2004 of $11,727 million were $1,130 million higher than 2003 due to improved realizations and higher production volumes. Earnings outside the U.S. for 2003 included a $1,700 million special item from a gain on the transfer of shares in Ruhrgas AG.

 

2003

 

Upstream earnings totaled $14,502 million, including $1,700 million from a gain on the transfer of shares in Ruhrgas AG. Absent this, Upstream earnings increased by $3,204 million from 2002 due to higher liquids and natural gas realizations. Total oil-equivalent production was down 1 percent. Liquids production of 2,516 Kbd increased 20 Kbd from 2002. Production increases from new projects in West Africa, Norway and Canada, and lower OPEC-driven quota constraints, were partly offset by natural field decline, operational problems in the North Sea and West Africa and the impact of the national strike in Venezuela. Natural gas production of 10,119 mcfd in 2003 compared with 10,452 mcfd in 2002. Higher demand in the first half of the year in Europe and contributions from new projects and work programs were more than offset by natural field decline, reduced entitlements and operational outages in the North Sea. Improved earnings from both U.S. and non-U.S. Upstream operations were driven by higher liquids and natural gas realizations. Earnings from U.S. Upstream operations for 2003 were $3,905 million, an increase of $1,381 million. Earnings outside the U.S. for 2003, including $1,700 million from a gain on the transfer of shares in Ruhrgas AG, were $10,597 million. Earnings outside the U.S. for 2002, including a special charge of $215 million relating to a United Kingdom tax rate change, were $7,074 million.

 

Downstream

 

     2004

   2003

   2002

     (millions of dollars)

Downstream

                    

United States

   $ 2,186    $ 1,348    $ 693

Non-U.S.

     3,520      2,168      607
    

  

  

Total

   $ 5,706    $ 3,516    $ 1,300
    

  

  

 

2004

 

Downstream earnings totaled $5,706 million, including a special charge of $550 million relating to the Allapattah lawsuit provision. Absent this, Downstream earnings increased $2,740 million due to stronger worldwide refining margins and higher refinery throughput partly offset by weaker marketing margins. Earnings also benefited from a planned reduction in inventories as a result of optimizing operations around the world. Petroleum product sales of 8,210 Kbd were 253 Kbd higher than 2003, largely related to increased refinery runs due to strong margins and more efficient operations. Refinery throughput was 5,713 Kbd compared with 5,510 Kbd in 2003. U.S. Downstream earnings of $2,186 million, including the one-time special charge relating to the Allapattah lawsuit provision, increased by $838 million. Non-U.S. Downstream earnings of $3,520 million were $1,352 million higher than 2003.

 

2003

 

Downstream earnings of $3,516 million increased by $2,216 million from 2002, reflecting higher worldwide refining and marketing margins. Earnings also benefited from a planned reduction in inventories as a result of optimizing operations around the world. Petroleum product sales of 7,957 Kbd were 200 Kbd higher than 2002, largely related to increased refinery runs due to strong margins and higher demand for distillates. Refinery throughput was 5,510 Kbd compared with 5,443 Kbd in 2002. U.S. Downstream earnings of $1,348 million increased by $655 million, reflecting higher refining and marketing margins partly offset by increased refinery turnaround activity in the year. Non-U.S. Downstream earnings of $2,168 million were $1,561 million higher than 2002 due to higher refining and marketing margins, increased refinery runs and positive inventory impacts.

 

Chemical

 

     2004

   2003

   2002

     (millions of dollars)

Chemical

                    

United States

   $ 1,020    $ 381    $ 384

Non-U.S.

     2,408    $ 1051      446
    

  

  

Total

   $ 3,428    $ 1,432    $ 830
    

  

  

 

2004

 

Chemical earnings of $3,428 million were up $1,996 million from 2003. Earnings benefited from improved worldwide margins, higher volumes and favorable foreign exchange effects. Prime product sales were a record 27,788 kt (thousands of metric tons), an increase of 1,221 kt from 2003, reflecting improved worldwide demand. Prime product sales are total chemical product sales including ExxonMobil’s share of equity company volumes and finished-product transfers to

 

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the Downstream business. Carbon black oil and sulfur volumes are excluded. U.S. Chemical earnings of $1,020 million were $639 million higher than 2003 with higher margins and increased volumes on improved demand. Non-U.S. Chemical earnings of $2,408 million were $1,357 million higher than 2003 due to higher margins, strong demand in Asia and favorable foreign exchange effects.

 

2003

 

Chemical earnings of $1,432 million were up $602 million from 2002. Earnings benefited from improved worldwide margins and favorable foreign exchange effects. Prime product sales of 26,567 kt were in line with sales of 26,606 kt in 2002. U.S. Chemical earnings of $381 million were $3 million lower than 2002 with higher margins offset by lower volumes on weaker demand. Non-U.S. Chemical earnings of $1,051 million were $605 million higher than 2002 due to higher margins, strong demand in Asia and favorable foreign exchange effects.

 

All Other Segments

 

     2004

    2003

   2002

 
     (millions of dollars)  

All other segments

                       

Corporate and financing

   $ (479 )   $ 1,510    $ (442 )

Merger-related expenses

     —         —        (275 )

Discontinued operations

     —         —        449  

Accounting change

     —         550      —    
    


 

  


Total

   $ (479 )   $ 2,060    $ (268 )
    


 

  


 

2004

 

Corporate and financing expenses in 2004 were $479 million. The corporate and financing segment contributed $1,510 million to earnings in 2003, including a special item of $2,230 million relating to the settlement of a long-running U.S. tax dispute. Excluding this special item, corporate and financing expenses were down $241 million mainly due to lower U.S. pension expense.

 

2003

 

All other segments totaled a gain of $2,060 million in 2003 compared to a loss of $268 million in 2002.

 

Corporate and financing in 2003, including $2,230 million relating to the settlement of a long-running U.S. tax dispute, contributed $1,510 million to earnings. Excluding this settlement, corporate and financing expenses increased by $278 million mainly due to higher U.S. pension expense.

 

Net income in 2003 included a $550 million positive impact for the required adoption of FAS 143 relating to accounting for asset retirement obligations.

 

Merger-related activities were completed in 2002 and net income included $275 million of merger-related expenses. Net income in 2002 also included discontinued operations earnings of $449 million, including a gain associated with the sale of the Chilean copper business.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Sources and Uses of Cash

 

     2004

    2003

 
     (millions of dollars)  

Net cash provided by/(used in)

                

Operating activities

   $ 40,551     $ 28,498  

Investing activities

     (14,910 )     (10,842 )

Financing activities

     (18,268 )     (14,763 )

Effect of exchange rate changes

     532       504  
    


 


Increase/(decrease) in cash and cash equivalents

   $ 7,905     $ 3,397  
    


 


     (Dec. 31)  

Cash and cash equivalents

   $ 18,531     $ 10,626  

Cash and cash equivalents – restricted

     4,604       —    
    


 


Total cash and cash equivalents

   $ 23,135     $ 10,626  
    


 


 

Cash and cash equivalents were $18,531 million at the end of 2004, an increase of $7,905 million, including $532 million of foreign exchange rate effects from the generally weaker U.S. dollar. Including restricted cash and cash equivalents of $4,604 million (see note 4 on page 57 and note 16 on page 70), total cash and cash equivalents of $23,135 million at the end of 2004 increased $12,509 million during the year. Cash and cash equivalents were $10,626 million at the end of 2003, an increase of $3,397 million, including $504 million of foreign exchange rate effects. Cash flows from operating, investing and financing activities are discussed below. For additional details, see the Consolidated Statement of Cash Flows on page 53.

 

Although the Corporation issues long-term debt from time to time and maintains a revolving commercial paper program, internally generated funds cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the Corporation’s immediate needs is carefully controlled, both to optimize returns on cash balances, and to ensure that it is secure and readily available to meet the Corporation’s cash requirements as they arise.

 

Production from existing oil and gas fields has declined about 6 percent on average over the past two years and is expected to continue to decline in the future at approximately the same rate. The impact on cash flows from production is highly dependent on crude oil and natural gas prices. Decline rates vary widely by individual field and the overall decline rate for a geographical area will be heavily influenced by the type of reservoir and age of the fields in that region.

 

The Corporation will need to continually find and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production and resulting cash flows in future periods. The Corporation has been successful in offsetting the effects of field decline through these measures and anticipates similar results in the future. Projects are in place or under way to increase production capacity. However, these volume increases are subject to a variety of risks including project execution, operational outages, reservoir performance, price effects on production sharing contracts and regulatory changes.

 

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The Corporation’s financial strength, as evidenced by its AAA/Aaa debt rating, enables it to make large, long-term capital expenditures. ExxonMobil currently expects to spend approximately $12 billion annually through the end of the decade on Upstream capital and exploration expenditures. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments. The purchase and sale of oil and gas properties have not had a significant impact on the amount or timing of operating cash flows.

 

Cash Flow from Operating Activities

 

2004

 

Cash provided by operating activities totaled $40.6 billion in 2004, a $12.1 billion increase from 2003. Major sources of funds were net income of $25.3 billion, which increased $3.8 billion, and noncash provisions of $9.8 billion for depreciation and depletion. Contributing to the increased level of cash provided by operating activities in 2004 was $2.4 billion of lower company contributions to pension plans and $3.0 billion of cash received related to the U.S. tax settlement recognized in earnings in 2003.

 

2003

 

Cash provided by operating activities totaled $28.5 billion in 2003, a $7.2 billion increase from 2002 influenced by higher net income. Major sources of funds were net income of $21.5 billion and noncash provisions of $9.0 billion for depreciation and depletion.

 

In 2003, ExxonMobil completed a divestment of interests in shares of Ruhrgas AG, a German gas transmission company. These shares were held in part by BEB Erdgas und Erdoel GmbH (BEB), an investment accounted for by the equity method, and in part by a consolidated affiliate in Germany. In 2002, cash in the amount of $1,466 million was received from BEB, an equity company, and included in cash flows from operating activities (see Ruhrgas transaction line on Consolidated Statement of Cash Flows, page 53). This cash from BEB was a loan and was part of a restructuring that enabled BEB to transfer its holdings in Ruhrgas AG provided regulatory approval was received. No income was recorded in 2002.

 

In 2003, upon receipt of regulatory approvals, the Ruhrgas AG shares held by BEB were transferred, cash was received for the shares held by the consolidated affiliate and a one-time gain of $1,700 million after tax was recognized in net income. The $2,240 million reduction in 2003 cash flow from operating activities reflects the pretax gains from the transaction. The cash generated from these gains for the BEB portion of the transaction was reported in 2002. For the shares held by the consolidated affiliate, the cash received was reported in cash flows from investing activities in 2003.

 

Cash Flow from Investing Activities

 

2004

 

Cash used in investing activities totaled $14.9 billion in 2004, $4.1 billion higher than 2003. Spending for property, plant and equipment decreased $0.9 billion. Proceeds from the sales of subsidiaries, investments and property, plant and equipment in 2004 increased $0.5 billion to $2.8 billion. As discussed in note 16 on page 70, investing activities in 2004 included a pledge by the Corporation of $4.6 billion of collateral consisting of cash and short-term, high-quality securities to the issuer of a litigation-related appeal bond. This collateral was reported as restricted cash and cash equivalents on the balance sheet.

 

2003

 

Cash used in investing activities totaled $10.8 billion in 2003, $1.0 billion higher than 2002. Spending for property, plant and equipment increased $1.4 billion, reflecting the Corporation’s active investment program. Proceeds from the sales of subsidiaries, investments and property, plant and equipment in 2003 were $2.3 billion, including $1.2 billion from the sale of an interest in Ruhrgas AG partly held by a consolidated affiliate.

 

Cash Flow from Financing Activities

 

2004

 

Cash used in financing activities was $18.3 billion, an increase of $3.5 billion from 2003, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.06 per share from $0.98 per share and totaled $6.9 billion, a payout of 27 percent. Total consolidated short-term and long-term debt declined $1.2 billion to $8.3 billion at year-end 2004. Shareholders’ equity increased $11.8 billion in 2004 to $101.7 billion, reflecting $25.3 billion of net income partly offset by distributions to ExxonMobil shareholders of $6.9 billion of dividends and $9.0 billion of net purchases of shares of ExxonMobil stock. Shareholders’ equity, and net assets and liabilities, also increased $2.2 billion, representing the foreign exchange translation effects of stronger foreign currencies on ExxonMobil’s operations outside the U.S.

 

During 2004, Exxon Mobil Corporation purchased 218 million shares of its common stock for the treasury at a gross cost of $10.0 billion. These purchases were to offset shares issued in conjunction with company benefit plans and programs and to reduce the number of shares outstanding. Shares outstanding were reduced from 6,568 million at the end of 2003 to 6,401 million at the end of 2004. Purchases were made in both the open market and through negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice.

 

2003

 

Cash used in financing activities was $14.8 billion, an increase of $3.4 billion from 2002, reflecting higher levels of debt reductions and purchases of ExxonMobil shares. Dividend payments on common shares increased to $0.98 per share from $0.92 per share and totaled $6.5 billion, a payout of 30 percent. Total consolidated short-term and long-term debt declined $1.2 billion to $9.5 billion at year-end 2003. Shareholders’ equity increased $15.3 billion in 2003 to $89.9 billion, reflecting $21.5 billion of net income partly offset by $6.5 billion of dividends paid to ExxonMobil shareholders and $5.4 billion of net

 

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purchases of shares of ExxonMobil stock. Shareholders’ equity, and net assets and liabilities, also increased $4.4 billion, representing the foreign exchange translation effects of stronger foreign currencies on ExxonMobil’s operations outside the U.S.

 

During 2003, Exxon Mobil Corporation purchased 163 million shares of its common stock for the treasury at a gross cost of $5.9 billion. These purchases were to offset shares issued in conjunction with company benefit plans and programs and to reduce the number of shares outstanding. Shares outstanding were reduced from 6,700 million at the end of 2002 to 6,568 million at the end of 2003. Purchases were made in both the open market and through negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice.

 

Commitments

 

Set forth below is information about the Corporation’s commitments outstanding at December 31, 2004. It provides data for easy reference from the consolidated balance sheet and from individual notes to the consolidated financial statements.

 

          Payments Due by Period

    

Commitments


   Note
Reference
Number


   2005

   2006-
2009


   2010
and
Beyond


   Total

     (millions of dollars)

Long-term debt (1)

   14    $ —      $ 666    $ 4,347    $ 5,013

– Due in one year (2)

          608      —        —        608

Asset retirement obligations (3)

   9      142      784      2,684      3,610

Pension obligations (4)

   17      1,703      1,576      5,531      8,810

Operating leases (5)

   10      1,323      2,813      1,855      5,991

Unconditional purchase obligations (6)

   16      602      1,918      2,125      4,645

Take-or-pay obligations (7)

          907      1,994      2,087      4,988

Firm capital commitments (8)

          3,823      2,069      529      6,421

 

This table excludes commodity purchase obligations (volumetric commitments but no fixed or minimum price) for which an active, highly liquid market exists and which are expected to be resold shortly after purchase. Examples include long-term, noncancelable upstream commitments with equity companies to purchase Qatar LNG production and downstream offtake commitments with equity companies and third parties to purchase refinery products at market prices. Inclusion of such amounts would not be meaningful in assessing liquidity and cash flow, since such market-based purchases will be offset in the same periods by cash received from sales.

 

Notes:

 

(1) Includes capitalized lease obligations of $354 million. Long-term debt amounts exclude the Corporation’s share of equity company debt, which is included in the calculation of return on average capital employed as shown on page 29.

 

(2) The amount due in one year is included in notes and loans payable of $3,280 million (note 6 on page 57).

 

(3) The discounted present value of upstream asset retirement obligations, primarily asset removal costs at the completion of field life.

 

(4) The amount by which accumulated benefit obligations (ABOs) exceeded the fair value of fund assets for certain U.S. and non-U.S. plans at year end (note 17 on page 72). For funded pension plans, this difference was $3.5 billion at December 31, 2004 (U.S. $0.9 billion, non-U.S. $2.6 billion). For unfunded plans, this was the ABO amount of $5.3 billion (U.S. $1.0 billion, non-U.S. $4.3 billion). The payments by period include expected contributions to funded pension plans in 2005 and estimated benefit payments for unfunded plans in all years.

 

(5) Minimum commitments for operating leases, shown on an undiscounted basis, cover drilling equipment, tankers, service stations and other properties.

 

(6) Unconditional purchase obligations (UPOs) are those long-term commitments that are noncancelable and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. The undiscounted obligations of $4,645 million mainly pertain to pipeline throughput agreements and include $2,513 million of obligations to equity companies. The present value of the total commitments, excluding imputed interest of $1,386 million, was $3,259 million.

 

(7) Take-or-pay obligations are noncancelable, long-term commitments for goods and services other than UPOs. The undiscounted obligations of $4,988 million mainly pertain to transportation, refining and natural gas purchases and include $503 million of obligations to equity companies. The present value of the total commitments, excluding imputed interest of $1,046 million, totaled $3,942 million.

 

(8) Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $6.4 billion. These commitments were predominantly associated with upstream projects outside the U.S., of which the largest single commitment outstanding at the end of 2004 was $1.6 billion associated with the development of crude oil and natural gas resources in Malaysia. The Corporation expects to fund the majority of these commitments through internal cash flow.

 

Guarantees

 

     Dec. 31, 2004

    

Equity
Company

Obligations


  

Other

Third-Party

Obligations


   Total

     (millions of dollars)

Guarantees of excise taxes/customs duties under reciprocal arrangements

   $ —      $ 1,122    $ 1,122

Other guarantees

     2,428      344      2,772
    

  

  

Total

   $ 2,428    $ 1,466    $ 3,894
    

  

  

 

The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2004, for $3,894 million, primarily relating to guarantees for notes, loans and performance under contracts (note 16 on page 71). This included $1,122 million representing guarantees of non-U.S. excise taxes and customs duties of other companies, entered into as a normal business practice, under reciprocal arrangements. Also included in this amount were guarantees by consolidated affiliates of $2,428 million, representing ExxonMobil’s share of obligations of certain equity companies. The above-mentioned guarantees are not reasonably likely to have a material current or future effect on the Corporation’s financial condition, changes in financial condition,

 

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Index to Financial Statements

revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

 

Financial Strength

 

On December 31, 2004, unused credit lines for short-term financing totaled approximately $5.2 billion (note 6 on page 57).

 

The table below shows the Corporation’s fixed-charge coverage and consolidated debt-to-capital ratios. The data demonstrate the Corporation’s creditworthiness. Throughout this period, the Corporation’s long-term debt securities maintained the top credit rating from both Standard and Poor’s (AAA) and Moody’s (Aaa), a rating it has sustained for 86 years.

 

     2004

    2003

    2002

Fixed-charge coverage ratio (times)

   36.1     30.8     13.8

Debt to capital (percent)

   7.3     9.3     12.2

Net debt to capital (percent) (1)

   (10.7 )   (1.2 )   4.4

Credit rating

   AAA/Aaa     AAA/Aaa     AAA/Aaa

 

(1) Debt net of cash, excluding restricted cash. The ratio of net debt to capital including restricted cash is (16.3) percent for 2004.

 

Management views the Corporation’s financial strength, as evidenced by the above financial ratios and other similar measures, to be a competitive advantage of strategic importance. The Corporation’s sound financial position gives it the opportunity to access the world’s capital markets in the full range of market conditions, and enables the Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

 

In addition to the above commitments, the Corporation makes limited use of derivative instruments, which are discussed in Risk Management on page 40 and note 13 on page 63.

 

Litigation and Other Contingencies

 

As discussed in note 16 to the consolidated financial statements, a number of lawsuits, including class actions, were brought in various courts against Exxon Mobil Corporation and certain of its subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. The vast majority of the compensatory claims have been resolved. All of the punitive damage claims were consolidated in the civil trial that began in May 1994.

 

In that trial, on September 24, 1996, the United States District Court for the District of Alaska entered a judgment in the amount of $5 billion in punitive damages to a class composed of all persons and entities who asserted claims for punitive damages from the Corporation as a result of the Exxon Valdez grounding. ExxonMobil appealed the judgment. On November 7, 2001, the United States Court of Appeals for the Ninth Circuit vacated the punitive damage award as being excessive under the Constitution and remanded the case to the District Court for it to determine the amount of the punitive damage award consistent with the Ninth Circuit’s holding. The Ninth Circuit upheld the compensatory damage award, which has been paid. On December 6, 2002, the District Court reduced the punitive damage award from $5 billion to $4 billion. Both the plaintiffs and ExxonMobil appealed that decision to the Ninth Circuit. The Ninth Circuit panel vacated the District Court’s $4 billion punitive damage award without argument and sent the case back for the District Court to reconsider in light of the recent U.S. Supreme Court decision in Campbell v. State Farm. On January 28, 2004, the District Court reinstated the punitive damage award at $4.5 billion plus interest. ExxonMobil and the plaintiffs appealed the decision to the Ninth Circuit. The Corporation has posted a $5.4 billion letter of credit. Management believes that the likelihood of the judgment being upheld is remote. While it is reasonably possible that a liability may have been incurred arising from the Exxon Valdez grounding, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability.

 

On December 19, 2000, a jury in Montgomery County, Alabama, returned a verdict against the Corporation in a dispute over royalties in the amount of $88 million in compensatory damages and $3.4 billion in punitive damages in the case of Exxon Corporation v. State of Alabama, et al. The verdict was upheld by the trial court on May 4, 2001. On December 20, 2002, the Alabama Supreme Court vacated the $3.5 billion jury verdict. The case was retried and on November 14, 2003, a state district court jury in Montgomery, Alabama, returned a verdict against Exxon Mobil Corporation. The verdict included $63.5 million in compensatory damages and $11.8 billion in punitive damages. On March 29, 2004, the district court judge reduced the amount of punitive damages to $3.5 billion. ExxonMobil believes the judgment is not justified by the evidence, that any punitive damage award is not justified by either the facts or the law, and that the amount of the award is grossly excessive and unconstitutional. ExxonMobil has appealed the decision. Management believes that the likelihood of the judgment being upheld is remote. While it is reasonably possible that a liability may have been incurred by ExxonMobil from this dispute over royalties, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability. On May 4, 2004, the Corporation posted a $4.5 billion supersedeas bond as required by Alabama law to stay execution of the judgment pending appeal. The Corporation has pledged to the issuer of the bond collateral consisting of cash and short-term, high-quality securities with an aggregate value of approximately $4.6 billion. This collateral is reported as restricted cash and cash equivalents on the Consolidated Balance Sheet on page 51. Under the terms of the pledge agreement, the Corporation is entitled to receive the income generated from the cash and securities and to make investment decisions, but is restricted from using the pledged cash and securities for any other purpose until such time the bond is canceled.

 

On May 22, 2001, a state court jury in New Orleans, Louisiana, returned a verdict against the Corporation and three other entities in a case brought by a landowner claiming damage to his property. The property had been leased by the landowner to a company that performed pipe cleaning and storage services for customers, including the Corporation. The jury awarded the plaintiff $56 million in compensatory damages (90 percent to be paid by the Corporation) and $1 billion in punitive damages (all to be paid by the Corporation). The damage related to the presence of naturally occurring radioactive material (NORM) on the site resulting from pipe cleaning operations. The award has been upheld at the trial court. ExxonMobil has appealed the judgment to the Louisiana Fourth Circuit Court of Appeals and believes that the judgment should be set aside or substantially reduced on factual and constitutional grounds. Management believes that the likelihood of the judgment being upheld is remote. While it is reasonably possible that a liability may have been incurred by ExxonMobil from this

 

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Index to Financial Statements

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

dispute over property damages, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability.

 

In Allapattah v. Exxon, a jury in the United States District Court for the Southern District of Florida determined in January 2001 that a class of all Exxon dealers between March 1983 and August 1994 had been overcharged between 1.03 and 1.4 cents per gallon for gasoline. Exxon sold a total of 39.8 billion gallons of gasoline to its dealers during this period. The estimated value of the potential claims associated with the 39.8 billion gallons of gasoline is $494 million. Including related interest, the total is approximately $1.3 billion. On June 11, 2003, the Eleventh Circuit Court of Appeals affirmed the judgment and on March 15, 2004, denied a petition for Rehearing En Banc. On October 12, 2004, the U.S. Supreme Court granted review of an issue raised by ExxonMobil as to whether the class in the District Court judgment should include members that individually do not satisfy the $50,000 minimum amount-in-controversy requirement in federal court. Members of the class could file claims through December 1, 2004. Claims representing over 90 percent of the gallons have been filed. In light of the Supreme Court’s decision to grant review of only part of ExxonMobil’s appeal, ExxonMobil took an after-tax charge of $550 million in the third quarter reflecting the estimated liability, including interest and after considering potential set-offs and defenses, for the claims in excess of $50,000.

 

Tax issues for 1983 to 1993 remain pending before the U.S. Tax Court. The ultimate resolution of these issues is not expected to have a materially adverse effect upon the Corporation’s operations or financial condition.

 

Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a materially adverse effect upon the Corporation’s operations or financial condition. There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.

 

CAPITAL AND EXPLORATION EXPENDITURES

 

     2004

   2003

     U.S.

   Non-U.S.

   U.S.

   Non-U.S.

     (millions of dollars)

Upstream (1)

   $ 1,922    $ 9,793    $ 2,125    $ 9,863

Downstream

     775      1,630      1,244      1,537

Chemical

     262      428      333      359

Other

     66      9      64      —  
    

  

  

  

Total

   $ 3,025    $ 11,860    $ 3,766    $ 11,759
    

  

  

  

 

(1) Exploration expenses included.

 

Capital and exploration expenditures in 2004 were $14.9 billion, reflecting the Corporation’s continued active investment program. Upstream spending was down 2 percent to $ 11.7 billion in 2004, from $ 12.0 billion in 2003, as a result of lower spending on major projects in the North Sea and the U.S. These decreases were partly offset by higher development drilling in Qatar, the Caspian and Russia. Capital and exploration expenditures are not tracked by the undeveloped and developed proved reserve categories. During the past three years, Upstream capital and exploration expenditures averaged $11.4 billion, and the Corporation currently expects to spend approximately $12 billion annually through the end of the decade. The majority of these expenditures are on major development projects, which typically take two to four years from the time of recording proved undeveloped reserves to the start of production from those reserves. The percentage of proved developed reserves has remained relatively stable over the past five years at over 60 percent of total proved reserves, indicating that proved reserves are consistently moved from undeveloped to developed status. Capital investments in the Downstream totaled $2.4 billion in 2004, down $0.4 billion from 2003, primarily reflecting reduced spending on low-sulfur motor fuels projects in North America. Total Chemical capital expenditures were essentially unchanged from 2003.

 

TAXES

 

     2004

    2003

    2002

 
     (millions of dollars)  

Income taxes

   $ 15,911     $ 11,006       6,499  

Excise taxes

     27,263     $ 23,855       22,040  

All other taxes and duties

     43,605       40,107       35,746  
    


 


 


Total

   $ 86,779     $ 74,968     $ 64,285  
    


 


 


Total effective tax rate

     40.3 %     36.4 %     39.8 %

 

2004

 

Income, excise and all other taxes totaled $86.8 billion in 2004, an increase of $ 11.8 billion, or 16 percent, from 2003. Income tax expense, both current and deferred, was $15.9 billion, $4.9 billion higher than 2003, reflecting higher pretax income in 2004. The effective tax rate was 40.3 percent in 2004, compared to 36.4 percent in 2003. Excluding the income tax effects in 2003 of the gain on the Ruhrgas AG share transfer and the settlement of a U.S. tax dispute, the effective rate in 2004 was similar to the prior year. During both periods, the Corporation continued to benefit from the favorable resolution of other tax-related issues. Excise and all other taxes and duties of $70.9 billion in 2004 increased $6.9 billion from 2003, reflecting higher prices and foreign exchange effects.

 

2003

 

Income, excise and all other taxes totaled $75.0 billion in 2003, an increase of $10.7 billion, or 17 percent, from 2002. Income tax expense, both current and deferred, was $11.0 billion, $4.5 billion higher than 2002, reflecting higher pretax income in 2003. The effective tax rate was 36.4 percent in 2003. Excluding the income tax effects of the 2003 gain on the Ruhrgas AG share transfer and settlement of a U.S. tax dispute, the effective rate in 2003 was similar to the prior year. During both periods, the Corporation continued to benefit from the favorable resolution of other tax-related issues. Excise and all other taxes and duties of $64.0 billion in 2003 increased $6.2 billion from 2002, reflecting higher prices and foreign exchange effects.

 

MERGER EXPENSES AND REORGANIZATION RESERVES

 

In association with the merger between Exxon and Mobil, $410 million pretax ($275 million after tax) of costs were recorded as merger-related expenses in 2002. Charges included separation expenses related to workforce reductions (approximately 8,200 employees at year-end 2002), plus implementation and merger closing costs. Merger-related expenses for the period 1999 to 2002 cumulatively totaled approximately $3.2 billion pretax. Reflecting the completion of merger-related activities, merger expenses were not reported in either 2003 or 2004.

 

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Index to Financial Statements

The following table summarizes the activity in the reorganization reserves. The 2002 opening balance represents accruals for provisions taken in prior years.

 

     Opening
Balance


   Additions

   Deductions

   Balance at
Year End


     (millions of dollars)

2002

   $ 197    $ 93    $ 189    $ 101

2003

     101      —        53      48

2004

     48      —        21      27

 

ASSET RETIREMENT OBLIGATIONS AND ENVIRONMENTAL COSTS

 

Asset Retirement Obligations

 

The methodology of accounting for asset retirement obligations was modified as of January 1, 2003, per FAS 143. The fair values of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time assets are installed, with an offsetting amount booked as additions to property, plant and equipment ($143 million for 2004). Over time, the liabilities are accreted for the increase in their present value, with this effect included in expenses ($136 million in 2004). Payments made for asset retirement obligations in 2004 were $201 million, and the ending balance of the obligations recorded on the balance sheet at December 31, 2004, totaled $3,610 million.

 

Environmental Costs

 

     2004

   2003

     (millions of dollars)

Capital expenditures

   $ 1,073    $ 1,306

Included in expenses

     1,781      1,497
    

  

Total

   $ 2,854    $ 2,803
    

  

 

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on the air, water and ground. This includes a significant investment in refining technology to manufacture low-sulfur motor fuels and projects to reduce nitrogen oxide and sulfur oxide emissions. ExxonMobil’s 2004 worldwide environmental costs for all such preventative and remediation steps were about $2.9 billion, of which $1.1 billion were capital expenditures and $1.8 billion were included in expenses. The total cost for such activities is expected to be about $3.0 billion in 2005 (with capital expenditures representing just over 40 percent of the total), and a similar amount is expected for 2006.

 

The Corporation accrues liabilities for environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites mitigates ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations, financial condition or liquidity. Provisions made in 2004 for new environmental liabilities were $340 million ($275 million in 2003), included in the $1.8 billion of 2004 expenses noted above, and the balance sheet reflects accumulated liabilities of $643 million as of December 31, 2004, and $528 million as of December 31, 2003.

 

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

 

Worldwide Average Realizations (1)


   2004

   2003

   2002

Crude oil and NGL ($/barrel)

   $ 34.76    $ 26.66    $ 22.30

Natural gas ($/kcf)

     4.48      3.98      2.65

 

(1) Consolidated subsidiaries.

 

Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have been varied, tending at times to be offsetting. In the Upstream, based on the 2004 worldwide production levels, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $400 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the worldwide average gas realization would have approximately a $200 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide a broad indicator of changes in the earnings experienced in any particular period.

 

In the very competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.

 

The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength, including the AAA and Aaa ratings of its long-term debt securities by Standard and Poor’s and Moody’s, as a competitive advantage.

 

In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes. Additionally, intersegment sales are market-related. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity and transportation capabilities. About 40 percent of the Corporation’s intersegment sales are crude oil produced by the Upstream and sold to the Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products.

 

Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to political events, OPEC actions and other factors, industry economics over the long term

 

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Index to Financial Statements

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

will continue to be driven by market supply and demand. Accordingly, the Corporation tests the viability of all of its assets based on long-term price projections. The Corporation’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs. Investment opportunities are tested against a variety of market conditions, including low-price scenarios. As a result, investments that would succeed only in highly favorable price environments are screened out of the investment plan.

 

The Corporation has had an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program involves a disciplined, regular review to ensure that all assets are contributing to the Corporation’s strategic and financial objectives. The result has been the creation of a very efficient capital base and has meant that the Corporation has seldom been required to write down the carrying value of assets, even during periods of low commodity prices.

 

Risk Management

 

The Corporation’s size, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses mitigate the Corporation’s risk from changes in interest rates, currency rates and commodity prices. The Corporation relies on these operating attributes and strengths to reduce enterprise-wide risk. As a result, the Corporation makes limited use of derivatives to offset exposures arising from existing transactions.

 

The Corporation does not trade in derivatives nor does it use derivatives with leverage features. The Corporation maintains a system of controls that includes a policy covering the authorization, reporting and monitoring of derivative activity. The Corporation’s derivative activities pose no material credit or market risks to ExxonMobil’s operations, financial condition or liquidity. Interest rate, foreign exchange rate and commodity price exposures arising from derivative contracts undertaken in accordance with the Corporation’s policies have not been significant.

 

Derivatives


   2004

   2003

    2002

 
     (millions of dollars)  

Net receivable/(payable)

   $ 6    $ (17 )   $ 20  

Net gain/(loss), before tax

     38    $ 4       (35 )

 

The fair values of derivatives outstanding and recorded on the balance sheet are shown in the table above. This is the amount that the Corporation would have paid to or received from third parties if these derivatives had been settled. These derivative fair values were substantially offset by the fair values of the underlying exposures being hedged. The gains/losses before tax include the offsetting amounts from the changes in fair value of the items being hedged by the derivatives. The fair value of derivatives outstanding at year-end 2004 and gain recognized during the year are immaterial in relation to the Corporation’s year-end cash balance of $18.5 billion, total assets of $195.3 billion or net income for the year of $25.3 billion.

 

Debt-Related Instruments

 

The Corporation is exposed to changes in interest rates, primarily as a result of its short-term debt and long-term debt carrying floating interest rates. The Corporation makes limited use of interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material to earnings, cash flow or fair value.

 

Foreign Currency Exchange Rate Instruments

 

The Corporation conducts business in many foreign currencies and is subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in foreign currency exchange rates on ExxonMobil’s geographically diverse operations are varied and often offsetting in amount. The Corporation makes limited use of currency exchange contracts to reduce the risk of adverse foreign currency movements related to certain foreign currency debt obligations. Exposure from market-rate fluctuations related to these contracts is not material. Aggregate foreign exchange transaction gains and losses included in net income are discussed in note 4 on page 57.

 

Commodity Instruments

 

The Corporation makes limited use of commodity forwards, swaps and futures contracts of short duration to mitigate the risk of unfavorable price movements on certain crude, natural gas and petroleum product purchases and sales. Commodity price exposure related to these contracts is not material.

 

Inflation and Other Uncertainties

 

The general rate of inflation in most major countries of operation has been relatively low in recent years, and the associated impact on costs has been countered by cost reductions from efficiency and productivity improvements.

 

The operations and earnings of the Corporation and its affiliates throughout the world have been, and may in the future be, affected from time to time in varying degree by political developments and laws and regulations, such as forced divestiture of assets; restrictions on production, imports and exports; price controls; tax increases and retroactive tax claims; expropriation of property; cancellation of contract rights; and environmental regulations. Both the likelihood of such occurrences and their overall effect upon the Corporation vary greatly from country to country and are not predictable.

 

RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS

 

In December 2004, the Financial Accounting Standards Board (FASB) issued a revised Statement of Financial Accounting Standards No. 123 (FAS 123R), “Share-based Payment.” FAS 123R requires compensation costs related to share-based payments to be recognized in the income statement over the vesting period. The amount of the compensation cost will be measured based on the grant-date fair value of the instrument issued. FAS 123R is effective as of July 1, 2005, for all awards granted or modified after that date and for those awards granted prior to that date that have not vested. FAS 123R will have no earnings impact on the Corporation because in 2003 the Corporation adopted a policy of expensing all share-based payments that is consistent with the provisions of FAS 123R, and all prior year outstanding awards have vested.

 

40


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Index to Financial Statements

EMERGING ACCOUNTING AND REPORTING ISSUES

 

Accounting for Suspended Well Costs

 

At its September 2004 meeting, the Emerging Issues Task Force (EITF) discussed Issue No. 04-9, “Accounting for Suspended Well Costs.” Statement of Financial Accounting Standards No. 19 (FAS 19), “Financial Accounting and Reporting by Oil and Gas Producing Companies,” requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs are included in wells, equipment and facilities. If, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed, net of any salvage value, within one year except under certain specific circumstances. Questions have arisen in practice about the application of this guidance. The EITF agreed to remove this issue from the EITF agenda and requested that the FASB consider an amendment to FAS 19 to address this issue. On February 4, 2005, the FASB issued a proposed FASB Staff Position (FSP) that would amend FAS 19 to permit the continued capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. Comments on the FSP are due back to the FASB in March 2005, and the guidance in the FSP would be applied prospectively in the first reporting period beginning after the FSP is finalized.

 

ExxonMobil continues to carry as an asset the cost of drilling exploratory wells that find sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure is made and drilling of additional exploratory wells is under way or firmly planned for the near future. Once exploration activities demonstrate that sufficient quantities of commercially producible reserves have been discovered, continued capitalization is dependent on project reviews, which take place at least annually, to ensure that sufficient progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria are charged to expense. ExxonMobil does not believe that this issue will have a material impact on its financial statements.

 

The following table shows the amount of suspended wells on the year-end balance sheet that were greater than one year old with no firm exploratory drilling planned.

 

     Dec. 31
2004


   Dec. 31
2003


     (millions of dollars)

Projects greater than one year old with no firm exploratory drilling planned

   $ 718    $ 693

Total suspended well cost

     1,070      1,093

 

Accounting for Purchases and Sales of Inventory with the Same Counterparty

 

At its November 2004 meeting, the EITF began discussion of Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” This Issue addresses the question of when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The EITF did not reach a consensus on this issue, but requested the FASB staff to further explore the alternative views.

 

ExxonMobil records certain crude oil, natural gas, petroleum product, and chemical purchases and sales of inventory entered into contemporaneously with the same counterparty as cost of sales and revenues, measured at fair value as agreed upon by a willing buyer and a willing seller. These transactions occur under contractual arrangements that establish the agreement terms either jointly, in a single contract, or separately, in individual contracts. This accounting treatment is consistent with long-term, predominant industry practice based on the Corporation’s knowledge of the industry (although the Corporation understands that some companies in the oil and gas industry may be accounting for these transactions differently as nonmonetary exchanges). Should the EITF reach a consensus on this Issue requiring these transactions to be recorded as exchanges measured at book value, the Corporation’s accounts “Sales and other operating revenue” and “Crude oil and product purchases” on the Consolidated Statement of Income would be lower by equal amounts with no impact on net income. All operating segments would be impacted by this change, but the largest effects are in the Downstream. The Corporation has not yet determined the amount by which “Sales and other operating revenue” and “Crude oil and product purchases” would be lower under this interpretation. A special effort is needed to accumulate this information manually since heretofore it has never been necessary to identify these monetary transactions separately from other monetary purchases and monetary sales. A best efforts estimate based on this undertaking is expected to be available in the second quarter of 2005. The Corporation does not believe this estimate will be material, but if it is, the information will be disclosed once it is available together with material changes in trends and uncertainties, if any.

 

CRITICAL ACCOUNTING POLICIES

 

The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The following summary provides further information about the critical accounting policies and the judgments that are made by the Corporation in the application of those policies.

 

Oil and Gas Reserves

 

Evaluations of oil and gas reserves are important to the effective management of upstream assets. They are integral to making investment decisions about oil and gas properties such as whether development should proceed or enhanced recovery methods should be undertaken. Oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation and evaluating for impairment. Oil and gas reserves are divided between proved and unproved reserves. Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty 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. Unproved reserves are those with less than reasonable certainty of recoverability and are classified as either probable or possible. Probable

 

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reserves are reserves that are more likely to be recovered than not, and possible reserves are less likely to be recovered than not.

 

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations and extrapolations of well information such as flow rates and reservoir pressure declines. In certain deepwater fields, proved reserves are recorded in a limited number of cases before flow tests are conducted because of the safety and cost implications of conducting the tests. In those situations, other industry-accepted analyses are used such as information from well logs, a thorough pressure and fluid sampling program, conventional core data obtained across the entire reservoir interval and nearby analog data. Historically, proved reserves recorded using these methods have been immaterial when compared to the Corporation’s total proved reserves and have also been validated by subsequent flow tests or actual production levels. Furthermore, the Corporation only records proved reserves for projects that have received significant funding commitments by management made toward the development of the reserves.

 

The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals (assisted by a central reserves group with significant technical experience) culminating in reviews with and approval by senior management. Notably, no employee is compensated based on the level of proved reserve bookings.

 

Key features of the reserves estimation process include:

 

    rigorous peer-reviewed technical evaluations and analysis of well and field performance information (such as flow rates and reservoir pressure declines), and

 

    a requirement that management make significant funding commitments toward the development of the reserves prior to booking.

 

Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.

 

Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves has remained relatively stable over the past five years at over 60 percent of total proved reserves (including both consolidated and equity reserves), indicating that proved reserves are consistently moved from undeveloped to developed status. Management is not aware of any factors that would significantly change this historical relationship in the next several years. Over time, these undeveloped reserves will be reclassified to the developed category as new wells are drilled, existing wells are recompleted and/or facilities to collect and deliver the production from existing and future wells are installed. Major development projects typically take two to four years from the time of recording proved reserves to the start of production from these reserves.

 

Based on regulatory guidance, the Corporation has reported 2004 reserves on the basis of December 31, 2004, prices and costs (“year-end prices”). Resultant changes from the year-end 2003 reserve estimates, which were based on long-term projections of oil and gas prices consistent with those used in the Corporation’s investment decision-making process, are shown in the line titled “Year-end price/cost revisions” on pages 83 and 84.

 

The use of year-end prices for reserves estimation introduces short-term price volatility into the process since annual adjustments will be required based on prices occurring on a single day. The Corporation believes that this approach is inconsistent with the long-term nature of the upstream business where production from individual projects often spans multiple decades. The use of prices from a single date is not relevant to the investment decisions made by the Corporation and annual variations in reserves based on such year-end prices are not of consequence to how the business is actually managed.

 

Performance-related revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data or (2) new geologic, reservoir or production data. This category can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity.

 

The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field. The Corporation uses this accounting policy instead of the “full cost” method because it provides a more timely accounting of the success or failure of the Corporation’s exploration and production activities. If the full cost method were used, all costs would be capitalized and depreciated on a country-by-country basis. The capitalized costs would be subject to an impairment test by country. The full cost method would tend to delay the expense recognition of unsuccessful projects.

 

Impact of Oil and Gas Reserves on Depreciation. The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of (1) actual volumes produced to (2) total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods) applied to the (3) asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. This variability has generally resulted in net upward revisions of proved reserves in existing fields, as more information becomes available through research and actual production levels. While the upward revisions the Corporation has made in the past are an indicator of variability, they have had a very small impact on the unit-of-production rates because they have been small compared to the large reserves base.

 

Impact of Oil and Gas Reserves and Prices on Testing for Impairment. Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

 

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The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.

 

The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses monitor the performance of assets against corporate objectives. They also assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. The impairment evaluation triggers include a significant decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and current negative operating losses.

 

In general, the Corporation does not view temporarily low oil prices as a triggering event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop precipitously, industry prices over the long term will continue to be driven by market supply and demand. On the supply side, industry production from mature fields is declining, but this is being offset by production from new discoveries and field developments. OPEC production policies also have an impact on world oil supplies. The demand side is largely a function of global economic growth. The relative growth/decline in supply versus demand will determine industry prices over the long term and these cannot be accurately predicted. Accordingly, any impairment tests that the Corporation performs make use of the Corporation’s long-term price assumptions for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used in the Corporation’s annual planning and budgeting processes and are also used for capital investment decisions. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and used for investment evaluation purposes. Cash flow estimates for impairment testing exclude the use of derivative instruments.

 

Supplemental information regarding oil and gas results of operations, capitalized costs and reserves can be found on pages 78 to 85. The standardized measure of discounted future cash flows on pages 86 and 87 is based on the year-end 2004 price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (FAS 69). Future prices used for any impairment tests will vary from the one used in the FAS 69 disclosure, and could be lower or higher for any given year.

 

Suspended Exploratory Well Costs

 

The Corporation carries as an asset the cost of drilling exploratory wells that find sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure is made and drilling of additional exploratory wells is under way or firmly planned for the near future. Once exploration activities demonstrate that sufficient quantities of commercially producible reserves have been discovered, continued capitalization is dependent on project reviews, which take place at least annually, to ensure that sufficient progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria are charged to expense.

 

The following table summarizes the year-end suspended exploratory well balances:

 

Exploration Suspended Drilling Costs


   2004

   2003

     (millions of dollars)

Projects with drilling in past 12 months (1)

   $ 207    $ 324

Projects with future exploratory drilling planned

     145      76

Other exploratory activities planned

     16      34
    

  

Subtotal – Projects with recent drilling or planned exploratory activity

     368      434
    

  

Projects requiring major capital expenditures

     621      519

Other projects progressing toward commercialization

     81      140
    

  

Subtotal – Projects with completed exploratory activity

     702      659
    

  

Total

   $ 1,070    $ 1,093
    

  

Number of wells at year end

     142      189

 

(1) Includes $68 million for 2004 and $107 million for 2003 for wells older than one year on projects with additional exploratory drilling in the past 12 months as part of an overall exploration program to evaluate the property.

 

The category “Other exploratory activities planned” includes wells whose continuing commercialization is dependent upon the results of additional seismic work that is either under way or planned. Significant advances in subsurface evaluation technologies have eliminated the need to drill as many exploratory wells as were required when FAS 19 was adopted in the late 1970s. The use of high-resolution 3-D seismic is a cost-effective technology that can eliminate the need for additional drilling in further defining the resource potential of a property.

 

The “Projects requiring major capital expenditures” category represents wells that require large capital projects (the Corporation’s share of development costs typically greater than $50 million, excluding developmental drilling) to develop significant amounts of hydrocarbon

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

resources discovered by these wells. Sufficient quantities of hydrocarbons have been discovered to justify a project. The timing for progressing these major projects to development is dependent upon factors such as lengthy negotiations with host governments, distance from markets and existing infrastructure, the effective deployment of existing technology, negotiations with joint venture partners on development plans and negotiations of long-term sales contracts, particularly if the reserves are in natural gas. These development activities are necessary to confirm whether the wells have found reserves that can be classified as proved, and often involve interfaces with a wide variety of regulatory bodies at the local, state and/or national level. In many cases required government approvals of proposed development plans have already been obtained, while in other cases development plan approvals are pending while the Corporation satisfies other regulatory requirements to maintain our rights to the resources.

 

The “Other projects progressing to commercialization” category includes both discoveries made near existing or already planned infrastructure, where the timing of development is driven by pipeline or facility capacity limitations, and smaller developments whose project timing is driven by negotiations with governments and co-venturers or the structuring of volume commitments under long-term sales contracts. In both cases, the existence of sufficient quantities of hydrocarbons to justify a project has been established, and deferral of well costs is a function of development timing.

 

The Corporation has a long history of converting exploration discoveries into successful projects and continued to progress activity on the suspended wells in 2004. Timing of proved reserve bookings will vary by individual project but the active, ongoing engagement of the Corporation’s Upstream organization to progress these opportunities is our standard practice. The following table provides further detail on wells included in the “Projects requiring major capital expenditures” and “Other projects progressing toward commercialization” categories:

 

Country/Project    2004    Year-End    
2004    
Wells    
  

Years    

Wells Drilled    

   Anticipated    
Year of Proved    
Reserve Booking    
  Comment
     (millions of dollars)                   

Angola

– Clochas/Tchihumba    

   $  20    2    2003    2008 - 2009   Development awaiting capacity in existing infrastructure.

– Marimba

       11    1    2001    2009 - 2010   Development in progress on first phase of Marimba deepwater project with proved reserves booked; development of second phase awaiting capacity in existing/planned infrastructure.

– Mavacola

     12    2    2001 - 2002    2007 - 2008   Development awaiting capacity in existing/planned infrastructure; planned subsea tieback to floating production system; submission of Declaration of Commerciality anticipated in 2005.

– Mondo/Saxi/Batuque    

     26    4    2000 - 2002    2005 - 2006   Planned subsea tieback to floating production system; initial project funding in 2003.

– Orquidea/Violeta

       6    2    1999 - 2001    2007 - 2008   Planned subsea tieback to floating production system; high-resolution 3-D seismic survey in 2004; submission of Declaration of Commerciality anticipated in 2005.

Australia

– Gorgon/Jansz

     73    17    1980 - 2003    2006 - 2007   Gorgon and Jansz resources to be developed as integrated LNG project; land access rights for onshore plant secured; negotiations with partners on unitized development plan are in progress.

– Kipper/Other

     10    3    1986 - 2001    2005 - 2006   Bass Strait project in design phase and progressing toward funding; planned tie-in to existing platform.

Bolivia

– Itau

     38    2    1999 - 2001    2008 - 2009   Changes in hydrocarbon law that would impact development of the Itau resource have been proposed and are being debated in Bolivian legislature; resolution required before a development plan can be finalized.

Canada

– Hebron

     32    2    1999 - 2000    2007 - 2008   Actively working development concept with co-venturer; recent efforts focused on further technical evaluation of wells and reservoir using seismic reprocessing and well core analysis.

– Terra Nova

       4    1    2001    2005 - 2006   Finalizing drilling plans to develop far east area of field in 2005.

 

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Country/Project    2004    Year-End    
2004    
Wells    
   Years Wells    
Drilled    
   Anticipated    
Year of Proved    
Reserve Booking    
  Comment
     (millions of dollars)                   

Indonesia

– Cepu

     46    6    1998 - 2001    2005 - 2006   Negotiations with government to extend license term are in progress; initial project funding and engineering began in 2001 with timely development anticipated upon conclusion of negotiations.

– Natuna

   118    4    1981 - 1983    2009 - 2010   Intent to proceed to the next phase of development communicated to government in 2004; discussions with government on near-term development work plans are in progress.

Nigeria

– Etoro-Isobo

         9    2    2002        2010 - 2011   Satellite development offshore Nigeria which will tie back to an existing production facility.

– Other

       16    5    2001 - 2002        2007 - 2012   Actively pursuing development of several smaller offshore satellite discoveries, which will tie back to existing production facilities.

Norway

– Fram

       22    3    1991 - 1997        2005 - 2006   Initial project funding began in 2003 and initial design work was completed in 2004; first production anticipated in 2006.

– Lavrans

       22    3    1995 - 1999        2016 - 2017   Development awaiting capacity in existing/planned infrastructure; planned subsea tieback to existing floating production system.

– Skarv/Snadd

       24    5    1998 - 2001        2007 - 2008   Assessment of export infrastructure alternatives and negotiations with partners on development plan are in progress; submission of Plan of Development anticipated in 2005.

– Other

       10    5    1992 - 2002        2005 - 2008   Progressing several smaller developments expected to result in proved reserve additions over next few years.

Papua New Guinea

– Hides

       35    2    1993 - 1998        2006 - 2007   Early engineering studies complete; negotiations with customers on sales terms are in progress; initial project funding and front-end engineering and design began in 2004.

Russia

– Sakhalin 1, Phase 3    

       26    4    1996 - 1998        2010 - 2011   Actively progressing the third phase of the Sakhalin 1 project to utilize capacity in facilities and infrastructure in Phase 1. Phase 1 development under way with first production anticipated in 2005.

United Kingdom

– Merganser

       13    3    1995        2005 - 2006   Development awaiting capacity in existing infrastructure; planned subsea tieback to existing U.K. North Sea facilities.

– Puffin

       42    4    1981 - 1986        2007 - 2008   Development awaiting capacity in existing infrastructure; planned tieback to existing U.K. North Sea production facility.

– Other

       24    4    2001 - 2003        2005 - 2007   Several smaller projects whose development timing is governed by capacity availability in existing infrastructure.

United States

– Point Thomson

       28    2    1977 - 1980        2006 - 2007   Annual Plan of Development work program approved by state; initial engineering design for gas cycling option complete; also progressing alternate development options including tie-in to proposed Alaska gas pipeline.

Other

– Various

       35    10    1979 - 2003        2005 - 2015    

Total

   $702    98              

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The timing of when proved reserves will be booked on the projects noted above is an estimate and subject to the uncertainties discussed under the heading “Factors Affecting Future Results” in Item 1 of ExxonMobil’s 2004 Form 10-K. Actual results could differ from estimates due to the factors noted in Item 1.

 

The following table shows the amount of suspended well costs that were written off in the past three years after the Corporation made the decision that projects were not commercially viable and proved reserves would not be booked. Total exploration expenses, including nonconsolidated interests, are also shown to provide context on the suspended well write-offs.

 

     2004

   2003

   2002

     (millions of dollars)

Suspended well write-offs

   $ 98    $ 238    $ 22

Total exploration expense

     1,133      1,033      957

 

Consolidations

 

The consolidated financial statements include the accounts of those significant subsidiaries that the Corporation controls. They also include the Corporation’s undivided interests in upstream assets and liabilities. Amounts representing the Corporation’s percentage interest in the underlying net assets of other significant affiliates that it does not control, but exercises significant influence, are included in “Investments and advances”; the Corporation’s share of the net income of these companies is included in the consolidated statement of income caption “Income from equity affiliates.” The accounting for these nonconsolidated companies is referred to as the equity method of accounting.

 

Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans and management compensation and succession plans.

 

The Corporation consolidates certain affiliates identified as variable-interest entities in which it has less than a majority ownership, because of guarantees or other arrangements that create majority economic interests in those affiliates that are greater than the Corporation’s voting interests.

 

Additional disclosures of summary balance sheet and income information for those subsidiaries accounted for under the equity method of accounting can be found in note 7 on page 58. The Corporation believes this to be important information necessary to a full understanding of the Corporation’s financial statements.

 

Investments in companies that are partially owned by the Corporation are integral to the Corporation’s operations. In some cases they serve to balance worldwide risks and in others they provide the only available means of entry into a particular market or area of interest. The other parties who also have an equity interest in these companies are either independent third parties or host governments that share in the business results according to their percentage ownership. The Corporation does not invest in these companies in order to remove liabilities from its balance sheet. In fact, the Corporation has long been on record supporting an alternative accounting method that would require each investor to consolidate its percentage share of all assets and liabilities in these partially owned companies rather than only the percentage in the net equity. This method of accounting for investments in partially owned companies is not permitted by GAAP except where the investments are in the direct ownership of a share in the upstream assets and liabilities. However, for purposes of calculating return on average capital employed, which is not covered by GAAP standards, the Corporation includes its share of debt of these partially owned companies in the determination of average capital employed.

 

Annuity Benefits

 

The Corporation and its affiliates sponsor approximately 100 defined-benefit (pension) plans in about 50 countries. The funding arrangement for each plan depends on the prevailing practices and regulations of the countries where the Corporation operates. Note 17, pages 72 to 75, provides details on pension obligations, fund assets and pension expense.

 

Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund. Book reserves are established for these plans because tax conventions and regulatory practices do not encourage advance funding. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.

 

For funded plans, including many in the U.S., pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities, and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes. Contributions to funded plans totaled $473 million in 2004 (all non-U.S.).

 

The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.

 

Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations, and the long-term rate for future salary increases. All the pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted only as appropriate to reflect changes in market rates and outlook. For example, the long-term expected earnings rate on U.S. pension plan assets in 2004 was 9.0 percent. This compares to an actual rate of return over the past decade of 12.5 percent. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected

 

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real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the pension fund earnings rate would increase annual pension expense by approximately $85 million before tax.

 

Under GAAP, differences between actual returns on fund assets versus the long-term expected return are not recorded in the year that the difference occurs, but rather are amortized in pension expense, along with other actuarial gains and losses, over the expected remaining service life of employees.

 

Due to the general increase in the market value of pension assets, pension expense declined from $1,938 million in 2003 (U.S. $1,015 million, non-U.S. $923 million) to $1,630 million in 2004 (U.S. $764 million, non-U.S. $866 million).

 

Litigation and Other Contingencies

 

A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits and tax disputes. These are summarized on pages 37 and 38, with a more extensive discussion included in note 16 on pages 70 and 71.

 

GAAP requires that liabilities for contingencies be recorded when it is probable that a liability has been incurred by the date of the balance sheet and that the amount can be reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information.

 

Significant management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past, and actual payments have not been material. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.

 

Foreign Currency Translation

 

The method of translating the foreign currency financial statements of the Corporation’s international subsidiaries into U.S. dollars is prescribed by GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment. Downstream and chemical operations normally use the local currency, except in highly inflationary countries, primarily Latin America, as well as in Singapore, which uses the U.S. dollar, because it predominantly sells into the U.S. dollar export market. Upstream operations also use the local currency as the functional currency, except where crude and natural gas production is predominantly sold in the export market in U.S. dollars. These operations, which use the U.S. dollar as their functional currency, are in Malaysia, Indonesia, Angola, Nigeria, Equatorial Guinea and the Middle East.

 

Factors considered by management when determining the functional currency for a subsidiary include: the currency used for cash flows related to individual assets and liabilities; the responsiveness of sales prices to changes in exchange rates; whether sales are into local markets or exported; the currency used to acquire raw materials, labor, services and supplies; sources of financing; and significance of intercompany transactions.

 

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

 

Management, including the Corporation’s chief executive officer, principal accounting officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of 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 this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2004.

 

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31,2004, was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

 

LOGO         LOGO         LOGO

Lee R. Raymond

       

Patrick T. Mulva

       

Donald D. Humphreys

Chief Executive Officer

       

Vice President and Controller

       

Vice President and Treasurer

         

(Principal Accounting Officer)

       

(Principal Financial Officer)

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

LOGO

 

To the Shareholders of Exxon Mobil Corporation:

 

We have completed an integrated audit of Exxon Mobil Corporation’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004, and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

 

Consolidated financial statements

 

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, shareholders’ equity and cash flows appearing on pages 50 to 77 present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, 2004, and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes 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. We believe that our audits provide a reasonable basis for our opinion.

 

As discussed in note 9 to the consolidated financial statements, the Corporation changed its method of accounting for asset retirement obligations in 2003.

 

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Index to Financial Statements

Internal control over financial reporting

 

Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Corporation maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Corporation’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

LOGO

 

Dallas, Texas

February 28, 2005

 

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Table of Contents
Index to Financial Statements

CONSOLIDATED STATEMENT OF INCOME

 

     Note
Reference
Number


   2004

   2003

   2002

          (millions of dollars)

Revenues and other income

                         

Sales and other operating revenue (1)

        $ 291,252    $ 237,054    $ 200,949

Income from equity affiliates

   7      4,961      4,373      2,066

Other income

          1,822      5,311      1,491
         

  

  

Total revenues and other income

        $ 298,035    $ 246,738    $ 204,506
         

  

  

Costs and other deductions

                         

Crude oil and product purchases

        $ 139,224    $ 107,658    $ 90,950

Production and manufacturing expenses

          23,225      21,260      17,831

Selling, general and administrative expenses

          13,849      13,396      12,356

Depreciation and depletion

          9,767      9,047      8,310

Exploration expenses, including dry holes

          1,098      1,010      920

Merger-related expenses

   3      —        —        410

Interest expense

          638      207      398

Excise taxes (1)

   19      27,263      23,855      22,040

Other taxes and duties

   19      40,954      37,645      33,572

Income applicable to minority and preferred interests

          776      694      209
         

  

  

Total costs and other deductions

        $ 256,794    $ 214,772    $ 186,996
         

  

  

Income before income taxes

        $ 41,241    $ 31,966    $ 17,510

Income taxes

   19      15,911      11,006      6,499
         

  

  

Income from continuing operations

        $ 25,330    $ 20,960    $ 11,011

Discontinued operations, net of income tax

   2      —        —        449

Cumulative effect of accounting change, net of income tax

          —        550      —  
         

  

  

Net income

        $ 25,330    $ 21,510    $ 11,460
         

  

  

Net income per common share (dollars)

   12                     

Income from continuing operations

        $ 3.91    $ 3.16    $ 1.62

Discontinued operations, net of income tax

          —        —        0.07

Cumulative effect of accounting change, net of income tax

          —        0.08      —  
         

  

  

Net income

        $ 3.91    $ 3.24    $ 1.69
         

  

  

Net income per common share – assuming dilution (dollars)

   12                     

Income from continuing operations

        $ 3.89    $ 3.15    $ 1.61

Discontinued operations, net of income tax

          —        —        0.07

Cumulative effect of accounting change, net of income tax

          —        0.08      —  
         

  

  

Net income

        $ 3.89    $ 3.23    $ 1.68
         

  

  

 

(1) Sales and other operating revenue includes excise taxes of $27,263 million for 2004, $23,855 million for 2003 and $22,040 million for 2002.

 

The information on pages 54 through 77 is an integral part of these statements.

 

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Table of Contents
Index to Financial Statements

CONSOLIDATED BALANCE SHEET

 

     Note
Reference
Number


   Dec. 31
2004


    Dec. 31
2003


 
          (millions of dollars)  

Assets

                     

Current assets

                     

Cash and cash equivalents

        $ 18,531     $ 10,626  

Cash and cash equivalents – restricted

   4, 16      4,604       —    

Notes and accounts receivable, less estimated doubtful amounts

   6      25,359       24,309  

Inventories

                     

Crude oil, products and merchandise

   1      8,136       7,665  

Materials and supplies

          1,351       1,292  

Prepaid taxes and expenses

          2,396       2,068  
         


 


Total current assets

        $ 60,377     $ 45,960  

Investments and advances

   8      18,404       15,535  

Property, plant and equipment, at cost, less accumulated depreciation and depletion

   9      108,639       104,965  

Other assets, including intangibles, net

          7,836       7,818  
         


 


Total assets

        $ 195,256     $ 174,278  
         


 


Liabilities

                     

Current liabilities

                     

Notes and loans payable

   6    $ 3,280     $ 4,789  

Accounts payable and accrued liabilities

   6      31,763       28,445  

Income taxes payable

          7,938       5,152  
         


 


Total current liabilities

        $ 42,981     $ 38,386  

Long-term debt

   14      5,013       4,756  

Annuity reserves

   17      10,850       9,609  

Accrued liabilities

          6,279       5,283  

Deferred income tax liabilities

   19      21,092       20,118  

Deferred credits and other long-term obligations

          3,333       2,829  

Equity of minority and preferred shareholders in affiliated companies

          3,952       3,382  
         


 


Total liabilities

        $ 93,500     $ 84,363  
         


 


Commitments and contingencies

   16                 

Shareholders’ equity

                     

Benefit plan related balances

        $ (1,014 )   $ (634 )

Common stock without par value (9,000 million shares authorized)

          5,067       4,468  

Earnings reinvested

          134,390       115,956  

Accumulated other nonowner changes in equity

                     

Cumulative foreign exchange translation adjustment

          3,598       1,421  

Minimum pension liability adjustment

          (2,499 )     (2,446 )

Unrealized gains/(losses) on stock investments

          428       511  

Common stock held in treasury (1,618 million shares in 2004 and 1,451 million shares in 2003)

          (38,214 )     (29,361 )
         


 


Total shareholders’ equity

        $ 101,756     $ 89,915  
         


 


Total liabilities and shareholders’ equity

        $ 195,256     $ 174,278  
         


 


 

The information on pages 54 through 77 is an integral part of these statements.

 

51


Table of Contents
Index to Financial Statements

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

 

          2004

    2003

   2002

 
     Note
Reference
Number


   Shareholders’
Equity


    Nonowner
Changes in
Equity


    Shareholders’
Equity


    Nonowner
Changes in
Equity


   Shareholders’
Equity


    Nonowner
Changes in
Equity


 
          (millions of dollars)  

Benefit plan related balances

                                                    

At beginning of year

        $ (634 )           $ (450 )          $ (159 )        

Restricted stock award

          (555 )             (358 )            (361 )        

Amortization

          173               107              11          

Other

          2               67              59          
         


         


        


       

At end of year

        $ (1,014 )           $ (634 )          $ (450 )        
         


         


        


       

Common stock

   12                                                

At beginning of year

          4,468               4,217              3,789          

Issued

          —                 —                —            

Other

          599               251              428          
         


         


        


       

At end of year

        $ 5,067             $ 4,468            $ 4,217          
         


         


        


       

Earnings reinvested

                                                    

At beginning of year

          115,956               100,961              95,718          

Net income for the year

          25,330     $ 25,330       21,510     $ 21,510      11,460     $ 11,460  

Dividends – common shares

          (6,896 )             (6,515 )            (6,217 )        
         


         


    &nbs