FORM 10-K
Table of Contents
Index to Financial Statements

2005


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, 2005

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 (6,106,332,510 shares
outstanding at January 31, 2006)

   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

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes   ü    No        

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes         No   ü    

 

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

 

            Large accelerated filer    ü           Accelerated filer                 Non-accelerated filer         

 

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

 

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2005, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $57.47 on the New York Stock Exchange composite tape, was in excess of $362 billion.

 

Documents Incorporated by Reference:

    Proxy Statement for the 2006 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, 2005

 

TABLE OF CONTENTS

 

     Page
Number


PART I
Item 1.   

Business

   1
Item 1A.   

Risk Factors

   2
Item 1B.   

Unresolved Staff Comments

   3
Item 2.   

Properties

   4
Item 3.   

Legal Proceedings

   19
Item 4.   

Submission of Matters to a Vote of Security Holders

   20
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]    20
PART II
Item 5.   

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

   21
Item 6.   

Selected Financial Data

   22
Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations    22
Item 7A.   

Quantitative and Qualitative Disclosures About Market Risk

   22
Item 8.   

Financial Statements and Supplementary Data

   23
Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure    23
Item 9A.    Controls and Procedures    23
Item 9B.    Other Information    23
PART III
Item 10.   

Directors and Executive Officers of the Registrant

   24
Item 11.   

Executive Compensation

   24
Item 12.   

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

   24
Item 13.   

Certain Relationships and Related Transactions

   24
Item 14.   

Principal Accounting Fees and Services

   24
PART IV
Item 15.   

Exhibits, Financial Statement Schedules

   24
Financial Section    25
Signatures    87
Index to Exhibits    89
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 commodity 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 as well as projects to reduce nitrogen oxide and sulfur oxide emissions. ExxonMobil’s 2005 worldwide environmental costs for all such preventative and remediation steps were about $3.3 billion, of which $1.2 billion were capital expenditures and $2.1 billion were included in expenses. The total cost for such activities is expected to remain in this range in 2006 and 2007 (with capital expenditures approximately 35 percent of the total).

 

Operating data and industry segment information for the Corporation are contained on pages 30, 73, 74 and 86; information on oil and gas reserves is contained on pages 80 through 83 and information on Company-sponsored research and development activities is contained on page 58 of the Financial Section of this report.

 

The number of regular employees was 83.7 thousand, 85.9 thousand and 88.3 thousand at years ended 2005, 2004 and 2003, 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 22.4 thousand, 19.3 thousand and 17.4 thousand at years ended 2005, 2004 and 2003, 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.

 

1


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Index to Financial Statements
Item 1A.     Risk Factors.

 

ExxonMobil’s financial and operating results are subject to a number of factors, many of which are not within the company’s control. These factors include the following:

 

Industry and Economic Factors:    The oil and gas business is fundamentally a commodity business. This means the operations and earnings of the Corporation and its affiliates throughout the world may be significantly affected by changes in oil, gas and petrochemical prices and by changes in margins on gasoline and other refined products. Oil, gas, petrochemical and product prices and margins in turn depend on local, regional and global events or conditions that affect supply and demand for the relevant commodity. 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 regional energy demand (such as the demand for heating oil or gas in winter) as well as severe weather events (such as hurricanes) that can disrupt supplies or interrupt the operation of ExxonMobil facilities;

 

    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.

 

Under certain market conditions, factors that have a positive impact on one segment of our business may have a negative impact on another segment and vice versa.

 

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 both industrial and individual consumers. The Corporation competes with other firms in the sale or purchase of needed goods and 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 businesses, is ExxonMobil’s ability to manage expenses successfully. This requires continuous management focus on reducing unit costs and improving efficiency including through technology improvements, cost control, productivity enhancements and regular reappraisal of our asset portfolio as described elsewhere in this report.

 

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 factors including:

 

    political instability or lack of well-established and reliable legal systems in areas where the Corporation operates;

 

    other political developments and laws and regulations (such as expropriation or forced divestiture of assets and unilateral cancellation or modification of contract terms, as well as de-regulation of certain energy markets);

 

    environmental regulations;

 

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Index to Financial Statements
    restrictions on exploration, production, imports and exports;

 

    restrictions on the Corporation’s ability to do business with certain countries, or to engage in certain areas of business within a country;

 

    price controls;

 

    tax or royalty increases (including retroactive claims);

 

    war or other international conflicts; and

 

    civil unrest.

 

Both the likelihood of these occurrences and their overall effect upon the Corporation vary greatly from country to country and are not predictable. A key component of the Corporation’s strategy for managing political risk is geographic diversification of the Corporation’s assets and operations.

 

Project Factors:    In addition to some of the factors cited above, ExxonMobil’s results depend upon the Corporation’s ability to develop and operate major projects and facilities as planned. The Corporation’s results will therefore be affected by events or conditions that impact the advancement, operation, cost or results of such projects or facilities, including:

 

    the outcome of negotiations with co-venturers, governments, suppliers, customers or others (including, for example, our ability to negotiate favorable long-term contracts with customers, or the development of reliable spot markets, that may be necessary to support the development of particular production projects);

 

    reservoir performance and natural field decline;

 

    changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping;

 

    security concerns or acts of terrorism that threaten or disrupt the safe operation of company facilities; and

 

    the occurrence of unforeseen technical difficulties (including technical problems that may delay start-up or interrupt production from an Upstream project or that may lead to unexpected downtime of refineries or petrochemical plants).

 

See section 1 of Item 2 of this report for a discussion of additional factors affecting future capacity growth and the timing and ultimate recovery of reserves.

 

Market Risk Factors:    See pages 40 and 41 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.

 

 

Item 1B.     Unresolved Staff Comments.

 

None.

 

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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 8, which note appears on page 60, and on pages 76 through 85.

 

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 2005

 

Estimated proved reserves are shown on pages 80 through 83 of the Financial Section of this report. No major discovery or other favorable or adverse event has occurred since December 31, 2005, that would cause a significant change in the estimated proved reserves as of that date. For information on the standardized measure of discounted future net cash flows relating to proved oil and gas reserves, see pages 84 and 85 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 80 through 83 of the Financial Section of this report for the year ended December 31, 2005. The Corporation has reported 2004 and 2005 proved reserves on the basis of December 31 prices and costs. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

 

     United
States


   Canada

   Europe

   Africa

  

Asia

Pacific/

Middle

East


  

Russia/

Caspian


  

South

America


  

Total

Consolidated


     (millions of barrels)

Liquids

   2,113    832    883    2,312    515    707    451    7,813
     (billions of cubic feet)

Natural gas

   13,692    1,705    8,398    841    7,279    821    619    33,355
     (millions of oil-equivalent barrels)

Oil-equivalent basis

   4,395    1,116    2,283    2,452    1,728    844    554    13,372

 

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

 

     Year-End 2005

   Year-End 2004

     Developed

   Undeveloped

   Developed

   Undeveloped

     (millions of oil-equivalent barrels)

Consolidated Subsidiaries

                   

United States

   3,411    984    3,726    922

Canada

   862    254    836    105

Europe

   1,711    572    1,942    603

Africa

   1,281    1,171    1,164    1,408

Asia Pacific/Middle East

   1,475    253    1,143    437

Russia/Caspian

   93    751    34    776

South America

   279    275    176    430
    
  
  
  

Total

   9,112    4,260    9,021    4,681
    
  
  
  

Equity Companies

                   

United States

   345    91    367    59

Europe

   1,713    468    1,649    627

Asia Pacific/Middle East

   1,938    2,629    1,404    2,007

Russia/Caspian

   713    373    740    399
    
  
  
  

Total

   4,709    3,561    4,160    3,092
    
  
  
  

 

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Index to Financial Statements

In the preceding reserves information, and in the reserves tables on pages 80 through 83 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 to grow over the period 2006-2010. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, asset sales, severe weather events, price effects on production sharing contracts and other factors as described in Item 1A—Risk Factors 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, commercial and market assessments and detailed analysis of well information such as flow rates and reservoir pressure declines. 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 2005, 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 2004, 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 and gas reserves reported on EIA-23 and those reported in the registrant’s Annual Report on Form 10-K for 2004 exceeds five percent.

 

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

 

Reference is made to pages 76 and 77 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 81 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 82 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 2005

   Year-End 2004

     Oil

   Gas

   Oil

   Gas

     Gross

   Net

   Gross

   Net

   Gross

   Net

   Gross

   Net

United States

   28,288    10,865    9,187    5,441    30,702    11,949    9,335    5,577

Canada

   5,967    5,214    6,115    2,991    7,156    5,890    5,663    2,752

Europe

   1,872    590    1,294    512    1,872    594    1,304    520

Africa

   674    277    14    6    562    235    18    7

Asia Pacific/Middle East

   1,991    532    259    180    2,078    577    235    172

Russia/Caspian

   77    16    2    1    63    13      

South America

   154    64    89    30    177    65    67    25
    
  
  
  
  
  
  
  

Total

   39,023    17,558    16,960    9,161    42,610    19,323    16,622    9,053
    
  
  
  
  
  
  
  

 

The numbers of wells operated at year-end 2005 were 17,351 gross wells and 14,028 net wells. At year-end 2004, the numbers of operated wells were 18,427 gross wells and 15,216 net wells.

 

5.    Gross and Net Developed Acreage

 

     Year-End 2005

   Year-End 2004

     Gross

   Net

   Gross

   Net

     (thousands of acres)

United States

   9,194    5,260    9,017    5,480

Canada

   5,615    2,238    5,535    2,499

Europe

   11,303    4,687    11,345    4,715

Africa

   1,497    545    1,179    475

Asia Pacific/Middle East

   7,876    1,570    10,116    2,436

Russia/Caspian

   531    116    487    103

South America

   690    232    1,331    388
    
  
  
  

Total

   36,706    14,648    39,010    16,096
    
  
  
  

 

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 2005

   Year-End 2004

     Gross

   Net

   Gross

   Net

     (thousands of acres)

United States

   10,388    6,413    10,913    7,055

Canada

   10,070    4,822    10,440    5,997

Europe

   8,782    2,778    8,418    2,245

Africa

   49,328    29,048    41,380    21,797

Asia Pacific/Middle East

   7,114    3,797    7,806    4,180

Russia/Caspian

   2,561    569    2,605    561

South America

   26,552    19,513    27,020    19,688
    
  
  
  

Total

   114,795    66,940    108,582    61,523
    
  
  
  

 

        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 from property to property. 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, many of the early licenses issued under the first four licensing rounds, provided for an initial term of six years with relinquishment of at least one-half of the original area at the end of the initial term, subject to extension for a further 40 years. ExxonMobil’s licenses issued in 2005 as part of the 23rd licensing round have an initial term of four years with a second term extension of four years and final term of 18 years. There is a mandatory relinquishment of 50-percent of acreage after the initial term and of all acreage that is not covered by a development plan at the end of the second term.

 

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.

 

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.

 

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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.

 

ASIA PACIFIC / MIDDLE EAST

 

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.

 

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Index to Financial Statements

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, depending on whether deep water areas or otherwise, with 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 (an additional extension of three years is possible in certain circumstances). 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.

 

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. The Government of Yemen awarded a five-year extension of the Marib PSA, but later repudiated the extension and expelled the concession holders. The parties are now in arbitration over the validity of the extension.

 

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.

 

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.

 

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Index to Financial Statements

RUSSIA/CASPIAN

 

Azerbaijan

 

The production sharing agreement (PSA) for the development of the Azeri-Chirag-Gunashli field 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.

 

Russia

 

Terms for ExxonMobil’s acreage are fixed by the production sharing agreement (PSA) that became effective in 1996 between the Russian government and the Sakhalin-1 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.

 

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 Association Agreements containing risk/profit provisions negotiated with the national oil company or its affiliates. Association Agreements are awarded for a term not to exceed 39 years. These agreements have an exploration and a production phase. The term of production begins after the exploration phase and runs for 20 years with the possibility of an extension, so long as the total contract term does not exceed 39 years.

 

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.

 

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8.    Number of Net Productive and Dry Wells Drilled

 

     2005

   2004

   2003

A. Net Productive Exploratory Wells Drilled

              

United States

   13    11    13

Canada

   1    2    13

Europe

   4    3    4

Africa

   5    2    4

Asia Pacific/Middle East

   1    2    2

Russia/Caspian

      1   

South America

         2
    
  
  

Total

   24    21    38
    
  
  

B. Net Dry Exploratory Wells Drilled

              

United States

   5    6    10

Canada

      4    9

Europe

   1    1    3

Africa

   5    4    3

Asia Pacific/Middle East

   1       3

Russia/Caspian

   1      

South America

        
    
  
  

Total

   13    15    28
    
  
  

C. Net Productive Development Wells Drilled

              

United States

   537    568    598

Canada

   263    466    297

Europe

   19    24    36

Africa

   61    64    59

Asia Pacific/Middle East

   50    35    68

Russia/Caspian

   7    4    2

South America

   9    3   
    
  
  

Total

   946    1,164    1,060
    
  
  

D. Net Dry Development Wells Drilled

              

United States

   8    13    14

Canada

   2    2    16

Europe

   2    2    2

Africa

         1

Asia Pacific/Middle East

   2    1    1

Russia/Caspian

        

South America

        
    
  
  

Total

   14    18    34
    
  
  

Total number of net wells drilled

   997    1,218    1,160
    
  
  

 

9.    Present Activities

 

A. Wells Drilling

 

     Year-End 2005

   Year-End 2004

     Gross

   Net

   Gross

   Net

United States

   148    84    179    81

Canada

   148    94    31    17

Europe

   46    12    32    8

Africa

   53    21    80    33

Asia Pacific/Middle East

   70    24    52    25

Russia/Caspian

   38    8    31    5

South America

   3    1    3    1
    
  
  
  

Total

   506    244    408    170
    
  
  
  

 

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B. Review of Principal Ongoing Activities in Key Areas

 

During 2005, 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 2005. At year-end 2005, ExxonMobil’s acreage totaled 11.7 million net acres, of which 3.0 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

 

During 2005, 514.3 net exploration and development wells were completed in the inland lower 48 states and 9.0 net development wells were completed offshore in the Pacific. An acid gas injection project was started up to increase existing plant capacity at the Shute Creek treating facility in La Barge, Wyoming, and tight gas development continues in the Piceance Basin of Colorado. Participation in Alaska production and development continued and a total of 23.7 net exploration and 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 engineering design for facility expansions.

 

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2005 was 2.8 million acres. A total of 16.2 net exploration and development wells were completed during the year. Installation of the semi-submersible production and drilling vessel, along with infrastructure to transport future oil and gas production onshore, continued for the Thunder Horse development in 2005. Startup, delayed due to a listing incident, is anticipated to occur in 2006.

 

CANADA

 

ExxonMobil’s year-end 2005 acreage holdings totaled 7.1 million net acres, of which 3.1 million net acres were offshore. A total of 266.7 net exploration and development wells were completed during the year. In eastern Canada, work continued on the Sable Compression project.

 

EUROPE

 

France

 

ExxonMobil’s acreage at year-end 2005 was 0.1 million net onshore acres.

 

Germany

 

A total of 2.3 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2005, with 7.6 net exploration and development wells drilled during the year.

 

Netherlands

 

ExxonMobil’s interest in licenses totaled 1.9 million net acres at year-end 2005, 1.5 million acres onshore and 0.4 million acres offshore. During 2005, 1.8 net exploration and development wells were

 

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drilled. Offshore, the first unmanned minimum facility monotower platform was successfully located on the K17-FA field. 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 2005 totaled approximately 1.0 million acres, all offshore. ExxonMobil participated in 7.7 net exploration and development well completions in 2005. Production was initiated at the Oseberg J field in June, the Aasgard Q field in August and the Kristin field in November 2005. The Sleipner A low pressure project and Ringhorne East, Oseberg Vestflanken, Fram East and Ormen Lange field developments are in progress.

 

United Kingdom

 

ExxonMobil’s net interest in licenses at year-end 2005 totaled approximately 2.1 million acres, all offshore. A total of 9.4 net exploration and development wells were completed during the year. The Arthur project commenced production in early 2005. Other projects progressed in 2005 include Caravel, Cutter, Merganser and Starling.

 

AFRICA

 

Angola

 

ExxonMobil’s year-end 2005 acreage holdings totaled 0.7 million net offshore acres and 12.0 net exploration and development wells were completed during the year. On Block 15, production began in July from the Kizomba B development and design work is complete on the Marimba development, which will tie-back to the Kizomba A Floating, Production, Storage and Offloading (FPSO) vessel. Planning for the Kizomba C development is ongoing. A block-wide 4D seismic acquisition program started late in the year. On Block 17, construction is underway on the Dalia and Rosa developments.

 

Cameroon

 

ExxonMobil’s acreage totaled 0.3 million net offshore acres at year-end 2005.

 

Chad

 

ExxonMobil’s net year-end 2005 acreage holdings consisted of 3.3 million onshore acres, with 35.6 net exploration and development wells completed during the year. Development of the Moundouli field is in progress.

 

Equatorial Guinea

 

ExxonMobil’s acreage totaled 0.4 million net offshore acres at year-end 2005, with 4.5 net development wells completed during the year.

 

Nigeria

 

ExxonMobil’s net acreage totaled 1.6 million offshore acres at year-end 2005, with 17.3 net exploration and development wells completed during the year. The ExxonMobil-operated Yoho field (OML 104) early production system was expanded, and the full field production platform was installed. The ExxonMobil-operated East Area Additional Oil Recovery platform was also installed, and detailed design and construction began on the ExxonMobil-operated East Area NGL II project. Production began in 2005 at the deepwater Bonga field (OML 118). Drilling continued at the ExxonMobil-operated deepwater Erha field (OPL 209), and the Erha FPSO vessel arrived. Construction continued on the

 

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Amenam-Kpono Phase 2 Gas project and Front End Engineering and Design (FEED) work was initiated on the deepwater Usan field (OPL 222).

 

ASIA PACIFIC / MIDDLE EAST

 

Australia

 

ExxonMobil’s net year-end 2005 acreage holdings totaled 1.2 million acres, all offshore. ExxonMobil drilled a total of 11.4 net exploration and development wells in 2005.

 

Indonesia

 

ExxonMobil had acreage of 2.5 million net acres at year-end 2005, 1.7 million acres offshore and 0.8 million acres onshore.

 

The production sharing contract for the Cepu Contract Area was signed in September 2005 by PT Pertamina (Persero) and ExxonMobil and approved by the Government of Indonesia. The term of the contract is 30 years. PT Pertamina (Persero) and ExxonMobil are currently working on the Joint Operation Agreement (JOA).

 

Japan

 

ExxonMobil’s net offshore acreage was 36 thousand acres at year-end 2005.

 

Malaysia

 

ExxonMobil has interests in production sharing contracts covering 0.5 million net acres offshore Malaysia at year-end 2005. During the year, a total of 25.6 net development wells were completed. Development and infill drilling wells were successfully completed at six platforms: Guntong-F, Irong Barat-C, Tapis-C, Semangkok-B, Angsi-A and Tiong-A. First oil was produced from the Guntong-F and Irong Barat-C platforms in 2005. Drilling activities are currently ongoing at Jerneh-A.

 

Papua New Guinea

 

A total of 0.5 million net onshore acres were held by ExxonMobil at year-end 2005, with 0.6 net development wells completed during the year.

 

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 I)

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

Ras Laffan Liquefied Natural Gas Company Limited — (RL I)

Ras Laffan Liquefied Natural Gas Company Limited (II) — (RL II)

Ras Laffan Liquefied Natural Gas Company Limited (3) — (RL 3)

 

In addition, production commenced in 2005 for ExxonMobil’s Al Khaleej Gas (AKG) project which supplies pipeline gas to domestic industrial customers. The AKG project will have a target peak production rate of 675 million of cubic feet per day (gross) and produce associated condensate, and commencing in early 2006 will produce LPG (Liquefied Petroleum Gas).

 

At the end of 2005, 54 (gross) wells supplied natural gas to currently producing LNG and pipeline gas sales facilities and drilling is underway to complete wells that will supply the new QG II, RL II and RL 3 projects. A total of 9.1 net exploration and development wells were completed in 2005.

 

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Qatar LNG capacity volumes at year-end included 9.7 MTA (millions of metric tons per annum) in QG I Trains 1-3 and a combined 16.0 MTA in RL I Trains 1-2 and RL II Trains 3-4. During 2005, production commenced at RL II Train 4, and an expansion project was completed to increase the capacity of QG I 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 Train 5 and RL 3 Trains 6-7 will add planned capacity of 4.7 MTA and 15.6 MTA, respectively, when complete.

 

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 I Trains 1-3, RL I Trains 1-2, RL II Trains 3 and 5, and approximately 49 BCF/MT for QG II Trains 4-5, RL II Train 4, and RL 3 Trains 6-7.

 

Republic of Yemen

 

ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 9.5 thousand acres onshore at year-end. During the year, 1.1 net development wells were drilled and completed.

 

Thailand

 

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2005.

 

United Arab Emirates

 

ExxonMobil’s net acreage in the Abu Dhabi oil concession was 0.5 million acres at year-end 2005, 0.4 million acres onshore and 0.1 million acres offshore. During the year, 6.7 net development wells were completed. The Bab Facility expansion project was completed and commissioning activities were begun for the Northeast Bab Phase I development project.

 

RUSSIA/CASPIAN

 

Azerbaijan

 

At year-end 2005, ExxonMobil’s net acreage, located in the Caspian Sea offshore of Azerbaijan, totaled 0.1 million acres. During the year, 0.7 net development wells were completed. At the Azeri-Chirag-Gunashli (ACG) development, the first phase of full-field development at Central Azeri came online in March 2005 and full-field oil production increased to 400 thousand barrels of oil per day (gross) by year-end. Commissioning of the second phase at West Azeri was in-progress at year-end, and construction is under way on the third phase at Deep Water Gunashli.

 

Kazakhstan

 

ExxonMobil’s net acreage totaled 0.3 million acres onshore and 0.2 million acres offshore at year-end 2005, with 3.2 net exploration and development wells completed during 2005. At Tengiz, construction of the 300 thousand barrels of oil per day (gross) expansion project continued through 2005. Engineering and construction of the initial phase of the Kashagan field continued during 2005.

 

Russia

 

ExxonMobil’s net acreage holdings at year-end 2005 were 85 thousand acres, all offshore. A total of 3.6 net development wells were completed in the Chayvo field during the year. Production from the

 

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field began in October 2005 through an early production system for domestic Russian oil and gas sales. Construction and drilling activities are progressing on Phase 1 full-field production and export systems. Phase 1 facilities 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.

 

SOUTH AMERICA

 

Argentina

 

ExxonMobil’s net acreage totaled 0.2 million onshore acres at year-end 2005, and there were 1.5 net development wells completed during the year.

 

Venezuela

 

ExxonMobil’s net year-end 2005 acreage holdings totaled 0.1 million onshore acres, with 7.1 net development wells completed during the year.

 

WORLDWIDE EXPLORATION

 

At year-end 2005, exploration activities were underway in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 42.8 net million acres were held at year-end 2005, and 0.8 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 1.6 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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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 separate 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 2005, this upgrading process yielded 0.853 barrels of synthetic crude oil per barrel of crude bitumen. In 2005 about 49 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 51 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 $2.8 billion at year end 2005.

 

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 1,890 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 4,485 million tons of extractable tar sands at an average bitumen grade of 11.2 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 2005 was equivalent to 738 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. The Aurora 2 mining and extraction development became fully operational in 2004. The Upgrader Expansion will be completed in 2006. When completed, this project will increase production capacity to 350 thousand barrels of synthetic crude oil per day (gross).

 

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ExxonMobil Share of Net Proven Syncrude Reserves(1)

 

     Synthetic Crude Oil

 
     Base Mine and
North Mine


    Aurora Mine

    Total

 
     (millions of barrels)  

January 1, 2005

   217     540     757  

Revision of previous estimate

            

Production

   (9 )   (10 )   (19 )
    

 

 

December 31, 2005

   208     530     738  
    

 

 


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

 

Syncrude Operating Statistics (total operation)

 

     2005

   2004

   2003

   2002

    2001

 

Operating Statistics

                           

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

   97.1    100.3    109.2    102.0     118.3  

Mined volume to tar sands ratio(1)

   1.02    0.94    1.15    1.05     1.15  

Tar sands mined (millions of tons)

   168.0    188.0    168.0    172.1     181.2  

Average bitumen grade (weight percent)

   11.1    11.1    11.0    11.2     11.0  
    
  
  
  

 

Crude bitumen in mined tar sands (millions of tons)

   18.6    20.9    18.5    19.2     19.9  

Average extraction recovery (percent)

   89.1    87.3    88.6    89.9     87.0  
    
  
  
  

 

Crude bitumen production (millions of barrels)(2)

   94.2    103.3    92.3    97.8     97.6  

Average upgrading yield (percent)

   85.3    85.5    86.0    86.3     84.5  
    
  
  
  

 

Gross synthetic crude oil produced (millions of barrels)

   79.3    88.4    78.4    84.8     82.4  

ExxonMobil net share (millions of barrels)(3)

   19    22    19    21     19  

(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.

 

Regarding a previously reported matter, the Corporation and the Texas Commission on Environmental Quality (“TCEQ”) have agreed to settle a Notice of Enforcement issued on August 29, 2003, alleging leak detection and repair violations and inadequate notifications of several emissions events as required by air quality regulations at ExxonMobil Oil Corporation’s (“EMOC”) Beaumont, Texas refinery. Under the terms of the settlement, EMOC has agreed to pay a civil penalty totaling $80,444, half of which will be paid through a supplemental environmental project involving county vehicle retrofits. The parties expect to execute an Agreed Order by the end of March 2006.

 

Regarding a previously reported matter, the Corporation signed an Administrative Consent Agreement in December 2005 setting forth the terms of settlement of an Administrative Consent Agreement and Enforcement Order regarding underground oil storage tank and air activities received from the Maine Department of Environmental Protection (“MDEP”) in March 2005. The MDEP alleged violations at 12 service stations of regulations under the state’s Stage II vapor

 

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recovery program and underground storage tank program, including those relating to record-keeping, monitoring, equipment, clean-up and testing. The Corporation paid a civil penalty of $269,400 for settlement of the alleged violations. The Agreement is awaiting final execution by the State of Maine.

 

In another previously reported matter, the Corporation and the Environmental Protection Agency (EPA) filed a Consent Agreement and Final Order with the Administrative Law Judge on January 9, 2006, reflecting the parties’ agreement to settle an Administrative Complaint captioned “In the Matter of ExxonMobil Production Company”. The EPA had alleged violations of the Clean Water Act at the Hawkins Field (in Wood County, Texas) related to 13 spills of produced water into potential waters of the United States occurring from June 2000 to August 2004. The Corporation has agreed to pay a $31,000 civil penalty and to perform a supplemental environmental project valued at $91,000 relating to enhanced detection of upset conditions at the Hawkins Field.

 

Refer to the relevant portions of note 14 beginning on page 68 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.

 


 

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

 

Name


  Age as of
March 16,
2006


  Title (Held Office Since)

R. W. Tillerson

  53   Chairman of the Board (2006)

D. D. Humphreys

  58   Senior Vice President (2006) and Treasurer (2004)

S. R. McGill

  63   Senior Vice President (2004)

J. S. Simon

  62   Senior Vice President (2004)

M. W. Albers

  49   President, ExxonMobil Development Company (2004)

A. T. Cejka

  54   Vice President (2004)

H. R. Cramer

  55   Vice President (1999)

P. J. Dingle

  57   Vice President (2003)

M. J. Dolan

  52   Vice President (2004)

M. E. Foster

  62   Vice President (2004)

H. H. Hubble

  53   Vice President—Investor Relations and Secretary (2004)

G. L. Kohlenberger

  53   Vice President (2002)

C. W. Matthews

  61   Vice President and General Counsel (1995)

P. T. Mulva

  54   Vice President and Controller (2004)

S. D. Pryor

  56   Vice President (2004)

P. E. Sullivan

  62   Vice President and General Tax Counsel (1995)

 

For at least the past five years, Messrs. Cramer, Humphreys, Matthews, McGill, Simon and Sullivan have been employed as executives of the registrant. Mr. Tillerson was a Senior Vice President and then President, a title he continues to hold, before becoming Chairman of the Board. Mr. Humphreys was Vice President and Controller and then Vice President and Treasurer before becoming Senior Vice President and Treasurer. 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. Mulva was Vice President—Investor Relations and Secretary before becoming Vice President and Controller.

 

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Index to Financial Statements

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, 2005.

 

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 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.

 

PART II

 

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

 

Reference is made to the quarterly information which appears on page 30 of the Financial Section of this report.

 

Issuer Purchases of Equity Securities for Quarter Ended December 31, 2005


 

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, 2005

   31,108,634    57.96    31,108,634       

November, 2005

   30,576,300    57.83    30,576,300       

December, 2005

   30,481,964    58.32    30,481,964       
    
       
      

Total

   92,166,898    58.04    92,166,898    (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.

 

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Index to Financial Statements

Item 6.    Selected Financial Data.

 

    Years Ended December 31,

    2005

  2004

    2003  

    2002  

  2001

    (millions of dollars, except per share amounts)

Sales and other operating revenue(1)(2)

  $ 358,955   $ 291,252   $ 237,054   $ 200,949   $ 208,715

(1) Excise taxes included

  $ 30,742   $ 27,263   $ 23,855   $ 22,040   $ 21,907

(2) Includes amounts for purchases/sales contracts with the same counterparty.

Net income

                             

Income from continuing operations

  $ 36,130   $ 25,330   $ 20,960   $ 11,011   $ 15,003

Discontinued operations, net of income tax

                449     102

Extraordinary gain, net of income tax

                    215

Cumulative effect of accounting change, net of income tax

            550        
   

 

 

 

 

Net income

  $ 36,130   $ 25,330   $ 21,510   $ 11,460   $ 15,320

Net income per common share

                             

Income from continuing operations

  $ 5.76   $ 3.91   $ 3.16   $ 1.62   $ 2.19

Discontinued operations, net of income tax

                0.07     0.01

Extraordinary gain, net of income tax

                    0.03

Cumulative effect of accounting change, net of income tax

            0.08        
   

 

 

 

 

Net income

  $ 5.76   $ 3.91   $ 3.24   $ 1.69   $ 2.23

Net income per common share - assuming dilution

                             

Income from continuing operations

  $ 5.71   $ 3.89   $ 3.15   $ 1.61   $ 2.17

Discontinued operations, net of income tax

                0.07     0.01

Extraordinary gain, net of income tax

                    0.03

Cumulative effect of accounting change, net of income tax

            0.08        
   

 

 

 

 

Net income

  $ 5.71   $ 3.89   $ 3.23   $ 1.68   $ 2.21
Cash dividends per common share   $ 1.14   $ 1.06   $ 0.98   $ 0.92   $ 0.91
Total assets   $ 208,335   $ 195,256   $ 174,278   $ 152,644   $ 143,174
Long-term debt   $ 6,220   $ 5,013   $ 4,756   $ 6,655   $ 7,099

 

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 31 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 40, 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.

 

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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, 2006, beginning on page 46 with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing to page 75;
    Quarterly Information (unaudited) appearing on page 30;
    Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited) appearing on pages 76 through 85; 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 financial officer and principal accounting officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2005. 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 financial officer and principal accounting 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, 2005.

 

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005, was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report beginning on page 46 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.

 

23


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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 2006 annual meeting of shareholders (the “2006 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 2006 Proxy Statement.

 

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

 

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 2006 Proxy Statement.

 

Item 13.    Certain Relationships and Related Transactions.

 

The Registrant has concluded that it has no disclosable matters under this item. Additional information regarding this determination is incorporated by reference to the portion entitled “Director and Officer Relationships” of the section entitled “Election of Directors” in the registrant’s 2006 Proxy Statement.

 

Item 14.    Principal Accounting Fees and Services.

 

Incorporated by reference to the section entitled “Ratification of Independent Auditors” of the registrant’s 2006 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 89 of this report.

 

24


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Index to Financial Statements

FINANCIAL SECTION

TABLE OF CONTENTS

 

Business Profile

   26

Financial Summary

   27

Frequently Used Terms

   28

Quarterly Information

   30

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

  

Functional Earnings

   31

Forward-Looking Statements

   32

Overview

   32

Business Environment and Risk Assessment

   32

Review of 2005 and 2004 Results

   33

Liquidity and Capital Resources

   35

Capital and Exploration Expenditures

   39

Taxes

   39

Asset Retirement Obligations and Environmental Costs

   40

Market Risks, Inflation and Other Uncertainties

   40

Recently Issued Statements of Financial Accounting Standards

   41

Critical Accounting Policies

   42
Management’s Report on Internal Control Over Financial Reporting    46
Report of Independent Registered Public Accounting Firm    46

Consolidated Financial Statements

  

Statement of Income

   48

Balance Sheet

   49

Statement of Shareholders’ Equity

   50

Statement of Cash Flows

   51
Notes to Consolidated Financial Statements   

  1. Summary of Accounting Policies

   52

  2. Accounting for Suspended Exploratory Well Costs

   55

  3. Miscellaneous Financial Information

   58

  4. Cash Flow Information

   58

  5. Additional Working Capital Information

   58

  6. Equity Company Information

   59

  7. Investments and Advances

   60

  8. Property, Plant and Equipment and Asset Retirement Obligations

   60

  9. Leased Facilities

   61

10. Earnings Per Share

   61

11. Financial Instruments and Derivatives

   62

12. Long-Term Debt

   62

13. Incentive Program

   67

14. Litigation and Other Contingencies

   68

15. Annuity Benefits and Other Postretirement Benefits

   70

16. Disclosures about Segments and Related Information

   73

17. Income, Excise and Other Taxes

   75
Supplemental Information on Oil and Gas Exploration and Production Activities    76

Operating Summary

   86

 

25


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Index to Financial Statements

BUSINESS PROFILE

 

     Earnings After
Income Taxes
    Average Capital
Employed
   Return on
Average
Capital
Employed
   Capital and
Exploration
Expenditures

Financial

   2005     2004     2005    2004    2005    2004    2005    2004
     (millions of dollars)    (percent)    (millions of dollars)

Upstream

                     

United States

   $ 6,200     $ 4,948     $ 13,491    $ 13,355    46.0    37.0    $ 2,142    $ 1,922

Non-U.S.

     18,149       11,727       39,770      37,287    45.6    31.5      12,328      9,793
                                                 

Total

   $ 24,349     $ 16,675     $ 53,261    $ 50,642    45.7    32.9    $ 14,470    $ 11,715
                                                 

Downstream

                     

United States

   $ 3,911     $ 2,186     $ 6,650    $ 7,632    58.8    28.6    $ 753    $ 775

Non-U.S.

     4,081       3,520       18,030      19,541    22.6    18.0      1,742      1,630
                                                 

Total

   $ 7,992     $ 5,706     $ 24,680    $ 27,173    32.4    21.0    $ 2,495    $ 2,405
                                                 

Chemical

                     

United States

   $ 1,186     $ 1,020     $ 5,145    $ 5,246    23.1    19.4    $ 243    $ 262

Non-U.S.

     2,757       2,408       8,919      9,362    30.9    25.7      411      428
                                                 

Total

   $ 3,943     $ 3,428     $ 14,064    $ 14,608    28.0    23.5    $ 654    $ 690
                                                 

Corporate and financing

     (154 )     (479 )     24,956      14,916    —      —        80      75
                                                 

Total

   $ 36,130     $ 25,330     $ 116,961    $ 107,339    31.3    23.8    $ 17,699    $ 14,885
                                                 

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

 

Operating

   2005    2004
     (thousands of barrels daily)

Net liquids production

     

United States

   477    557

Non-U.S.

   2,046    2,014
         

Total

   2,523    2,571
         
     (millions of cubic feet daily)

Natural gas production available for sale

     

United States

   1,739    1,947

Non-U.S.

   7,512    7,917
         

Total

   9,251    9,864
         
     (thousands of oil-equivalent
barrels daily)

Oil-equivalent production (1)

   4,065    4,215

 

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

 

     2005    2004
     (thousands of barrels daily)

Petroleum product sales

     

United States

   2,915    2,872

Non-U.S.

   5,342    5,338
         

Total

   8,257    8,210
         
     (thousands of barrels daily)

Refinery throughput

     

United States

   1,794    1,850

Non-U.S.

   3,929    3,863
         

Total

   5,723    5,713
         
     (thousands of metric tons)

Chemical prime product sales

     

United States

   10,369    11,521

Non-U.S.

   16,408    16,267
         

Total

   26,777    27,788
         

 

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FINANCIAL SUMMARY

 

     2005     2004     2003     2002     2001  
     (millions of dollars, except per share amounts)  

Sales and other operating revenue (1)

   $ 358,955     $ 291,252     $ 237,054     $ 200,949     $ 208,715  

Earnings

          

Upstream

   $ 24,349     $ 16,675     $ 14,502     $ 9,598     $ 10,736  

Downstream

     7,992       5,706       3,516       1,300       4,227  

Chemical

     3,943       3,428       1,432       830       707  

Corporate and financing

     (154 )     (479 )     1,510       (442 )     (142 )

Merger-related expenses

     —         —         —         (275 )     (525 )
                                        

Income from continuing operations

   $ 36,130     $ 25,330     $ 20,960     $ 11,011     $ 15,003  

Discontinued operations

     —         —         —         449       102  

Extraordinary gain

     —         —         —         —         215  

Accounting change

     —         —         550       —         —    
                                        

Net income

   $ 36,130     $ 25,330     $ 21,510     $ 11,460     $ 15,320  
                                        

Net income per common share

          

Income from continuing operations

   $ 5.76     $ 3.91     $ 3.16     $ 1.62     $ 2.19  

Net income per common share – assuming dilution

          

Income from continuing operations

   $ 5.71     $ 3.89     $ 3.15     $ 1.61     $ 2.17  

Discontinued operations, net of income tax

     —         —         —         0.07       0.01  

Extraordinary gain, net of income tax

     —         —         —         —         0.03  

Cumulative effect of accounting change, net of income tax

     —         —         0.08       —         —    
                                        

Net income

   $ 5.71     $ 3.89     $ 3.23     $ 1.68     $ 2.21  
                                        

Cash dividends per common share

   $ 1.14     $ 1.06     $ 0.98     $ 0.92     $ 0.91  

Net income to average shareholders’ equity (percent)

     33.9       26.4       26.2       15.5       21.3  

Working capital

   $ 27,035     $ 17,396     $ 7,574     $ 5,116     $ 5,567  

Ratio of current assets to current liabilities

     1.58       1.40       1.20       1.15       1.18  

Additions to property, plant and equipment

   $ 13,839     $ 11,986     $ 12,859     $ 11,437     $ 9,989  

Property, plant and equipment, less allowances

   $ 107,010     $ 108,639     $ 104,965     $ 94,940     $ 89,602  

Total assets

   $ 208,335     $ 195,256     $ 174,278     $ 152,644     $ 143,174  

Exploration expenses, including dry holes

   $ 964     $ 1,098     $ 1,010     $ 920     $ 1,175  

Research and development costs

   $ 712     $ 649     $ 618     $ 631     $ 603  

Long-term debt

   $ 6,220     $ 5,013     $ 4,756     $ 6,655     $ 7,099  

Total debt

   $ 7,991     $ 8,293     $ 9,545     $ 10,748     $ 10,802  

Fixed-charge coverage ratio (times)

     50.2       36.1       30.8       13.8       17.7  

Debt to capital (percent)

     6.5       7.3       9.3       12.2       12.4  

Net debt to capital (percent) (2)

     (22.0 )     (10.7 )     (1.2 )     4.4       5.3  

Shareholders’ equity at year end

   $ 111,186     $ 101,756     $ 89,915     $ 74,597     $ 73,161  

Shareholders’ equity per common share

   $ 18.13     $ 15.90     $ 13.69     $ 11.13     $ 10.74  

Weighted average number of common shares outstanding (millions)

     6,266       6,482       6,634       6,753       6,868  

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

     83.7       85.9       88.3       92.5       97.9  

CORS employees not included above (thousands) (4)

     22.4       19.3       17.4       16.8       19.9  

 

(1) Sales and other operating revenue includes excise taxes of $30,742 million for 2005, $27,263 million for 2004, $23,855 million for 2003, $22,040 million for 2002 and $21,907 million for 2001. Includes amounts for purchases/sales contracts with the same counterparty.

 

(2) Debt net of cash, excluding restricted cash. The ratio of net debt to capital including restricted cash is (28.3) percent for 2005.

 

(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


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Index to Financial Statements

FREQUENTLY USED TERMS

Listed below are definitions of several of ExxonMobil’s key business and 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 and regular disciplined 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    

   2005    2004    2003
     (millions of dollars)

Net cash provided by operating activities

   $ 48,138    $ 40,551    $ 28,498

Sales of subsidiaries, investments and property, plant and equipment

     6,036      2,754      2,290
                    

Cash flow from operations and asset sales

   $ 54,174    $ 43,305    $ 30,788
                    

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    

   2005     2004     2003  
     (millions of dollars)  

Business uses: asset and liability perspective

      

Total assets

   $ 208,335     $ 195,256     $ 174,278  

Less liabilities and minority share of assets and liabilities

      

Total current liabilities excluding notes and loans payable

     (44,536 )     (39,701 )     (33,597 )

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

     (41,095 )     (41,554 )     (37,839 )

Minority share of assets and liabilities

     (4,863 )     (5,285 )     (4,945 )

Add ExxonMobil share of debt-financed equity company net assets

     3,450       3,914       4,151  
                        

Total capital employed

   $ 121,291     $ 112,630     $ 102,048  
                        

Total corporate sources: debt and equity perspective

      

Notes and loans payable

   $ 1,771     $ 3,280     $ 4,789  

Long-term debt

     6,220       5,013       4,756  

Shareholders’ equity

     111,186       101,756       89,915  

Less minority share of total debt

     (1,336 )     (1,333 )     (1,563 )

Add ExxonMobil share of equity company debt

     3,450       3,914       4,151  
                        

Total capital employed

   $ 121,291     $ 112,630     $ 102,048  
                        

 

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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    

   2005     2004     2003  
     (millions of dollars)  

Net income

   $ 36,130     $ 25,330     $ 21,510  

Financing costs (after tax)

      

Third-party debt

     (1 )     (137 )     (69 )

ExxonMobil share of equity companies

     (144 )     (185 )     (172 )

All other financing costs – net (1)

     (295 )     54       1,775  
                        

Total financing costs

     (440 )     (268 )     1,534  
                        

Earnings excluding financing costs

   $ 36,570     $ 25,598     $ 19,976  
                        

Average capital employed

   $ 116,961     $ 107,339     $ 95,373  

Return on average capital employed – corporate total

     31.3 %     23.8 %     20.9 %

 

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

 

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QUARTERLY INFORMATION

 

     2005    2004
    

First

Quarter

   Second
Quarter
   Third
Quarter
   Fourth
Quarter
   Year    First
Quarter
   Second
Quarter
   Third
Quarter
   Fourth
Quarter
   Year

Volumes

                             
     (thousands of barrels daily)

Production of crude oil and natural gas liquids

     2,544    2,468    2,451    2,629    2,523      2,635    2,581    2,505    2,565    2,571

Refinery throughput

     5,749    5,727    5,764    5,652    5,723      5,596    5,589    5,809    5,852    5,713

Petroleum product sales

     8,229    8,259    8,217    8,322    8,257      8,126    8,023    8,242    8,446    8,210
     (millions of cubic feet daily)

Natural gas production available for sale

     10,785    8,709    7,716    9,822    9,251      11,488    9,061    8,488    10,430    9,864
     (thousands of oil-equivalent barrels daily)

Oil-equivalent production (1)

     4,341    3,919    3,737    4,266    4,065      4,550    4,091    3,920    4,303    4,215
     (thousands of metric tons)

Chemical prime product sales

     6,938    6,592    6,955    6,292    26,777      6,792    6,930    7,117    6,949    27,788

Summarized financial data

                             
     (millions of dollars)

Sales and other operating revenue (2)

   $ 79,475    86,622    96,731    96,127    358,955    $ 66,060    69,220    74,854    81,118    291,252

Gross profit (3)

   $ 31,525    32,962    35,336    36,841    136,664    $ 27,619    28,202    29,655    33,560    119,036

Net income

   $ 7,860    7,640    9,920    10,710    36,130    $ 5,440    5,790    5,680    8,420    25,330

Per share data

                             
     (dollars per share)

Net income per common share

   $ 1.23    1.21    1.60    1.72    5.76    $ 0.83    0.89    0.88    1.31    3.91

Net income per common share – assuming dilution

   $ 1.22    1.20    1.58    1.71    5.71    $ 0.83    0.88    0.88    1.30    3.89

Dividends per common share

   $ 0.27    0.29    0.29    0.29    1.14    $ 0.25    0.27    0.27    0.27    1.06

Common stock prices

                             

High

   $ 64.37    61.74    65.96    63.89    65.96    $ 43.40    45.53    49.79    52.05    52.05

Low

   $ 49.25    52.78    57.60    54.50    49.25    $ 39.91    41.43    44.20    48.18    39.91

 

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

 

(2) Includes excise taxes and amounts for purchases/sales with the same counterparty.

 

(3) Gross profit equals sales and other operating revenue less estimated costs associated with products sold.

The price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil common stock is traded. The principal market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States.

There were 616,344 registered shareholders of ExxonMobil common stock at December 31, 2005. At January 31, 2006, the registered shareholders of ExxonMobil common stock numbered 614,599.

On January 25, 2006, the Corporation declared a $0.32 dividend per common share, payable March 10, 2006.

 

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

 

FUNCTIONAL EARNINGS    

   2005     2004     2003
     (millions of dollars, except per share amounts)

Net Income (U.S. GAAP)

      

Upstream

      

United States

   $ 6,200     $ 4,948     $ 3,905

Non-U.S.

     18,149       11,727       10,597

Downstream

      

United States

     3,911       2,186       1,348

Non-U.S.

     4,081       3,520       2,168

Chemical

      

United States

     1,186       1,020       381

Non-U.S.

     2,757       2,408       1,051

Corporate and financing

     (154 )     (479 )     1,510
                      

Income from continuing operations

   $ 36,130     $ 25,330     $ 20,960

Accounting change

     —         —         550
                      

Net income

   $ 36,130     $ 25,330     $ 21,510
                      

Net income per common share

   $ 5.76     $ 3.91     $ 3.24

Net income per common share – assuming dilution

   $ 5.71     $ 3.89     $ 3.23

Special items included in net income

      

Non-U.S. Upstream

      

Gain on Dutch gas restructuring

   $ 1,620     $ —       $ —  

Gain on transfer of Ruhrgas shares

   $ —       $ —       $ 1,700

U.S. Downstream

      

Allapattah lawsuit provision

   $ (200 )   $ (550 )   $ —  

Non-U.S. Downstream

      

Sale of Sinopec shares

   $ 310     $ —       $ —  

Non-U.S. Chemical

      

Sale of Sinopec shares

   $ 150     $ —       $ —  

Joint venture litigation

   $ 390     $ —       $ —  

Corporate and financing

      

U.S. tax settlement

   $ —       $ —       $ 2,230

 

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

FORWARD-LOOKING STATEMENTS

Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including demand growth and mix; capacity increases; production growth and mix; 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 in Item 1A of ExxonMobil’s 2005 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. Our 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 87 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 risk-assessed near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Volumes are based on individual field production profiles, which are also updated annually. Prices for crude oil, natural gas and refined 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 RISK ASSESSMENT

Long-Term Business Outlook

By 2030, the world’s population is expected grow to 8 billion, approximately 25 percent higher than today’s level. Coincident with this population increase, the Corporation expects worldwide economic growth to average just under 3 percent per year. This combination of population and economic growth should lead to a primary energy demand increase of approximately 50 percent by 2030. The vast majority (80 percent) of the increase is expected to occur in developing countries.

As demand rises, energy efficiency will become increasingly important, with the pace of improvement likely to accelerate. This accelerated pace is the outcome of expected improvements in personal transportation and power generation driven by the introduction of new technologies, as well as a myriad of other improvements which span the residential, commercial and industrial sectors.

Fossil fuels, including coal, are expected to remain the predominant energy sources with approximately 80 percent share of total energy. Oil and gas alone are expected to be about 60 percent. These well-established fuel sources are the only ones with the versatility and scale to meet the majority of the world’s growing energy needs. Nuclear power will likely be a growing option to meet electricity needs. Alternative fuels, such as solar and wind power, will grow rapidly, underpinned by government subsidies and mandates. But even with assumptions of robust 10 percent per year growth, solar and wind are expected to represent just 1 percent of the total energy portfolio by 2030.

        Oil demand should grow at 1.4 percent per year, primarily due to the increasing number of light duty vehicles in the transportation sector, partly offset by improvements in fuel efficiency. Natural gas and coal are both expected to grow at 1.8 percent annually driven primarily by increased need for electric power generation. The Corporation expects the liquefied natural gas (LNG) market to quintuple by 2030, 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.

The Corporation expects the world’s reserve base to grow not only from new discoveries, but also from increases to known reserves. Technology will underpin these increases. The cost to develop these reserves is also 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, or $5 trillion in total.

Upstream

ExxonMobil maintains the largest portfolio of development and exploration 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 production on line, the Corporation expects a shift in the geographic mix of its production volumes between now and 2010. Oil and natural gas output from West Africa, the Caspian, the Middle East and Russia is expected to more than double during the next five years based on current capital project execution plans. Currently, these growth areas account for just over 25 percent of the Corporation’s production. By the end of the decade, they are expected to generate about 50 percent of total volumes. The remainder of the Corporation’s production is expected to be sourced from established areas, including Europe and North America.

 

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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 25 percent to 35 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 to grow over the period 2006-2010. However, actual volumes will vary from year to year due to timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, asset sales, severe weather events, price effects under production sharing contracts and other factors described in Item 1A of ExxonMobil’s 2005 Form 10-K.

Downstream

The downstream industry environment remains very competitive. While refining margins in 2005 were strong, our long-term real refining margins have declined at a rate of about 1 percent per year over the past 20 years. The intense competition in the retail fuels market has similarly driven down real margins by about 4 percent per year. Global refining capacity is expected to grow at about 1 to 2 percent per year through 2010 with Asia Pacific expected to grow at more than 3 percent per year. ExxonMobil assets are well-positioned to supply the growing demand for petroleum products and our continuous focus on making our refineries more efficient and productive has resulted in significant capacity increases to help meet growing demand at a fraction of the cost of building a new refinery. Our capacity growth rate over the past 10 years at existing facilities has been the equivalent of building a new mid-sized refinery every 3 years.

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 factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, seasonality and weather and political climate. This global market and trade flow was particularly evident following the 2005 supply disruptions in the United States caused by hurricanes Katrina and Rita. Fuel prices increased when 25 percent of U.S. refining capacity was shut down. Consumers reduced demand, and additional product imports flowed into the United States. Supply and demand came back into balance quickly, with an associated decline in prices.

The objectives of ExxonMobil’s Downstream strategies are to position the Corporation to be the industry leader under a variety of market conditions. These strategies include maintaining best-in-class operations in all aspects of the business, maximizing value from leading-edge technology, capitalizing on integration with other ExxonMobil businesses, and providing high 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 150 thousand barrels per day. ExxonMobil’s fuels and lubes marketing business portfolios include operations in over 150 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.

Chemical

Petrochemical demand continued to be supported by a strong global economy in 2005, although reduced product availability and demand in the United States in the aftermath of hurricanes Katrina and Rita impacted sales volumes. Asian demand was strong, driven by economic and industrial production growth. ExxonMobil benefited from continued strong reliability of its operations, as well as a portfolio of products that 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, Chemical also has a diverse portfolio of less-cyclical business lines. Chemical’s competitive advantages are achieved through its business mix, broad geographic coverage, investment discipline, integration of chemical capacity with large refining complexes or Upstream gas processing, operational excellence, leading proprietary technology and product application expertise.

REVIEW OF 2005 AND 2004 RESULTS

 

     2005    2004    2003
     (millions of dollars)

Income from continuing operations

   $ 36,130    $ 25,330    $ 20,960

Accounting change

     —        —        550
                    

Net income (U.S. GAAP)

   $ 36,130    $ 25,330    $ 21,510
                    

2005

Net income in 2005 of $36,130 million was the highest ever for the Corporation, up $10,800 million from 2004. Net income in 2005 included special items of $2,270 million, consisting of a $1,620 million gain related to the Dutch gas restructuring, a $460 million gain from the sale of the Corporation’s stake in Sinopec, a $390 million gain from the resolution of joint venture litigation and a charge of $200 million relating to the Allapattah lawsuit provision.

Total assets at December 31, 2005, of $208 billion increased by approximately $13 billion from 2004, reflecting strong earnings and the Corporation’s active investment program, particularly in the Upstream.

2004

Net income in 2004 of $25,330 million was up $3,820 million from 2003. Net income in 2004 included a special charge of $550 million relating to Allapattah. 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.

 

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

Upstream

 

     2005    2004    2003
     (millions of dollars)

Upstream

        

United States

   $ 6,200    $ 4,948    $ 3,905

Non-U.S.

     18,149      11,727      10,597
                    

Total

   $ 24,349    $ 16,675    $ 14,502
                    

2005

Upstream earnings totaled $24,349 million, including $1,620 million from a gain related to the Dutch gas restructuring. Absent this, Upstream earnings increased $6,054 million from 2004 due to higher liquids and natural gas realizations partly offset by lower production volume. Oil equivalent production was down 4 percent versus 2004 including the impact of hurricanes Katrina and Rita, as well as divestment and entitlement effects. Excluding these impacts, total oil equivalent production decreased by 1 percent. Liquids production of 2,523 kbd (thousands of barrels daily) decreased by 48 kbd from 2004. Production increases from new projects in West Africa, the North Sea and North America were offset by natural field decline in mature areas, the impact of hurricanes Katrina and Rita, as well as divestment and entitlement effects. Natural gas production of 9,251 mcfd (millions of cubic feet daily) decreased 613 mcfd from 2004. Higher volumes from projects in Qatar, the North Sea and North America were offset by mature field decline, the impact of hurricanes Katrina and Rita, maintenance activity, lower European demand, as well as entitlement and divestment impacts. Improved earnings from both U.S. and non-U.S. Upstream operations were driven by higher liquids and natural gas realizations, partly offset by lower production volumes. Earnings from U.S. Upstream operations for 2005 were $6,200 million, an increase of $1,252 million. Earnings outside the U.S. for 2005, including the $1,620 million gain related to the Dutch gas restructuring, were $18,149 million, an increase of $6,422 million.

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 gain on the transfer of shares in Ruhrgas AG. Absent this, Upstream earnings increased $3,873 million in 2004. Oil equivalent production was flat with 2003 including price-related entitlement effects and divestment impacts. Excluding these impacts, total oil-equivalent production was up 3 percent versus 2003. Liquids production of 2,571 kbd 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 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 from a gain on the transfer of shares in Ruhrgas AG.

Downstream

 

     2005    2004    2003
     (millions of dollars)

Downstream

        

United States

   $ 3,911    $ 2,186    $ 1,348

Non-U.S.

     4,081      3,520      2,168
                    

Total

   $ 7,992    $ 5,706    $ 3,516
                    

2005

Downstream earnings totaled $7,992 million, including a gain of $310 million for the Sinopec share sale and a special charge of $200 million relating to the Allapattah lawsuit provision. Downstream earnings for 2004 also included a charge of $550 million for Allapattah. Absent these, Downstream earnings increased $1,626 million from 2004 reflecting stronger worldwide refining margins partly offset by weaker marketing margins. Petroleum product sales of 8,257 kbd increased from 8,210 kbd in 2004. Refinery throughput was 5,723 kbd compared with 5,713 kbd in 2004. U.S. Downstream earnings of $3,911 million increased by $1,725 million, including the charges in both years related to Allapattah. Non-U.S. Downstream earnings of $4,081 million, including a gain for the Sinopec share sale, were $561 million higher than 2004.

2004

Downstream earnings totaled $5,706 million, including a special charge of $550 million relating to Allapattah. 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 charge relating to Allapattah, increased by $838 million. Non-U.S. Downstream earnings of $3,520 million were $1,352 million higher than 2003.

Chemical

 

     2005    2004    2003
     (millions of dollars)

Chemical

        

United States

   $ 1,186    $ 1,020    $ 381

Non-U.S.

     2,757      2,408      1,051
                    

Total

   $ 3,943    $ 3,428    $ 1,432
                    

2005

Chemical earnings totaled $3,943 million, including a $390 million gain from the favorable resolution of joint venture litigation and $150 million from a gain on the Sinopec share sale. Absent these, Chemical earnings decreased $25 million from 2004 due to lower volumes, partially offset by higher worldwide margins. Prime product sales were 26,777 kt (thousands of metric tons), a decrease of 1,011 kt from 2004, largely reflecting the impact of hurricanes Katrina and Rita. 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 $1,186 million increased by $166 million. Non-U.S. Chemical earnings increased by $349 million to $2,757 million, including the impact of the gain from the resolution of the joint venture litigation of $390 million and a gain of $150 million on the Sinopec share sale.

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, an increase of 1,221 kt from 2003, reflecting improved worldwide demand. 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.

All Other Segments

 

     2005     2004     2003
     (millions of dollars)

All other segments

      

Corporate and financing

   $ (154 )   $ (479 )   $ 1,510

Accounting change

     —         —         550
                      

Total

   $ (154 )   $ (479 )   $ 2,060
                      

2005

Corporate and financing expenses were $154 million compared with $479 million in 2004. The decrease of $325 million is mainly due to higher interest income.

2004

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

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

 

     2005     2004  
     (millions of dollars)  

Net cash provided by/(used in)

    

Operating activities

   $ 48,138     $ 40,551  

Investing activities

     (10,270 )     (14,910 )

Financing activities

     (26,941 )     (18,268 )

Effect of exchange rate changes

     (787 )     532  
                

Increase/(decrease) in cash and cash equivalents

   $ 10,140     $ 7,905  
                
     (Dec. 31)  

Cash and cash equivalents

   $ 28,671     $ 18,531  

Cash and cash equivalents – restricted

     4,604       4,604  
                

Total cash and cash equivalents

   $ 33,275     $ 23,135  
                

Cash and cash equivalents were $28,671 million at the end of 2005, an increase of $10,140 million, including $(787) million of foreign exchange rate effects from the general strengthening of the U.S. dollar in 2005. Including restricted cash and cash equivalents of $4,604 million (see note 3 on page 58 and note 14 on page 68), total cash and cash equivalents were $33,275 million at the end of 2005. 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 in 2004. Including restricted cash and cash equivalents of $4,604 million, total cash and cash equivalents of $23,135 million at the end of 2004 increased $12,509 million during the year. Cash flows from operating, investing and financing activities are discussed below. For additional details, see the Consolidated Statement of Cash Flows on page 51.

        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.

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. After a period of production at plateau rates, it is the nature of oil and gas fields eventually to produce at declining rates for the remainder of their economic life. Averaged over all our existing oil and gas fields and without new projects, ExxonMobil’s entitlement production is expected to decline at approximately six percent per year through the end of the decade, consistent with recent historical performance. Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type of reservoir, fluid properties, recovery mechanisms, and age of the field. Furthermore, the Corporation’s production entitlements for individual fields can vary with price and contractual terms.

The Corporation has long been successful at offsetting the effects of natural field decline through disciplined investments and anticipates similar results in the future. Projects are in progress or planned to increase production capacity. However, these volume increases are subject to a variety of risks including project start-up timing, operational outages, reservoir performance, crude oil and natural gas prices, severe weather events, and regulatory changes. The Corporation’s cash flows are also highly dependent on crude oil and natural gas prices.

The Corporation’s financial strength, as evidenced by its AAA/Aaa debt rating, enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2005 were $17.7 billion, reflecting the corporation’s continued active investment program. The Corporation expects spending to continue in this range for the next several years, although actual spending could vary depending on progress of individual projects. 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 cash flows from operating activities.

 

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

Cash Flow from Operating Activities

2005

Cash provided by operating activities totaled $48.1 billion in 2005, a $7.5 billion increase from 2004. Major sources of funds were net income of $36.1 billion, which increased $10.8 billion, and non-cash provisions of $10.3 billion for depreciation and depletion. Contributing to the increased level of cash provided by operating activities in 2005 was the net timing effect of receipts of notes and accounts receivable and payments of accounts and other payables in a rising price environment.

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 non-cash 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.

Cash Flow from Investing Activities

2005

Cash used in investing activities totaled $10.3 billion in 2005, $4.6 billion lower than 2004. In 2004, the Corporation pledged $4.6 billion as bond collateral for a litigation appeal (see 2004 comments below). Spending for property, plant and equipment increased $1.9 billion. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $6.0 billion in 2005 increased $3.3 billion, including almost $1.4 billion from the sale of the Corporation’s interest in Sinopec.

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 14 on page 68, 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.

Cash Flow from Financing Activities

2005

Cash used in financing activities was $26.9 billion, an increase of $8.6 billion from 2004, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.14 per share from $1.06 per share and totaled $7.2 billion, a payout of 20 percent. Total consolidated short-term and long-term debt declined $0.3 billion to $8.0 billion at year-end 2005. Shareholders’ equity increased $9.5 billion in 2005, to $111.2 billion, reflecting $36.1 billion of net income partly offset by distributions to ExxonMobil shareholders of $7.2 billion of dividends and $16.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding. Shareholders’ equity, and net assets and liabilities, also decreased $2.6 billion, representing the foreign exchange translation effects of weaker foreign currencies at the end of 2005 on ExxonMobil’s operations outside the U.S.

During 2005, Exxon Mobil Corporation purchased 311 million shares of its common stock for the treasury at a gross cost of $18.2 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 4.2 percent from 6,401 million at the end of 2004 to 6,133 million at the end of 2005. 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.

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 $8.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding. 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 2.5 percent 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.

 

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Commitments

Set forth below is information about the Corporation’s commitments outstanding at December 31, 2005. 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
   2006    2007-
2010
   2011
and
Beyond
   Total
     (millions of dollars)

Long-term debt (1)

   12    $ —      $ 583    $ 5,637    $ 6,220

– Due in one year (2)

        515      —        —        515

Asset retirement obligations (3)

   8      143      788      2,637      3,568

Pension obligations (4)

   15      1,582      1,528      4,961      8,071

Operating leases (5)

   9      1,505      3,895      1,560      6,960

Unconditional purchase obligations (6)

   14      569      1,909      2,098      4,576

Take-or-pay obligations (7)

        983      2,740      2,288      6,011

Firm capital commitments (8)

        4,105      2,341      1,129      7,575

This table excludes commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold shortly after purchase, either in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing terms. Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices. Inclusion of such commitments would not be meaningful in assessing liquidity and cash flow, because these purchases will be offset in the same periods by cash received from the related sales transactions.

Notes:

 

(1) Includes capitalized lease obligations of $197 million. Long-term debt amounts exclude the Corporation’s share of equity company debt.

 

(2) The amount due in one year is included in notes and loans payable of $1,771 million (note 5 on page 58).

 

(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. For funded pension plans, this difference was $2.8 billion at December 31, 2005 (U.S. $1.2 billion, non-U.S. $1.6 billion). For unfunded plans, this was the ABO amount of $5.3 billion (U.S. $1.1 billion, non-U.S. $4.2 billion). The payments by period include expected contributions to funded pension plans in 2006 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 $4,576 million mainly pertain to pipeline throughput agreements and include $2,324 million of obligations to equity companies. The present value of the total commitments, excluding imputed interest of $1,248 million, was $3,328 million.

 

(7) Take-or-pay obligations are noncancelable, long-term commitments for goods and services other than UPOs. The undiscounted obligations of $6,011 million mainly pertain to transportation and refining purchases and include $2,008 million of obligations to equity companies. The present value of the total commitments, excluding imputed interest of $1,287 million, totaled $4,724 million.

 

(8) Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $7.6 billion. These commitments were predominantly associated with Upstream projects outside the U.S., of which the two largest commitments outstanding at the end of 2005 were $1.9 billion and $1.4 billion associated with the development of crude oil and natural gas resources in Malaysia and Kazakhstan, respectively. The Corporation expects to fund the majority of these commitments through internal cash flow.

Guarantees

The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2005, for $3,893 million, primarily relating to guarantees for notes, loans and performance under contracts (note 14 on page 68). This included $1,020 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 $2,649 million, representing ExxonMobil’s share of obligations of certain equity companies. The below mentioned guarantees are not reasonably likely to have a material current or future effect on the Corporation’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

 

     Dec. 31, 2005
     Equity
Company
Obligations
  

Other

Third-Party

Obligations

   Total
     (millions of dollars)

Guarantees of excise taxes/customs duties under reciprocal arrangements

   $ —      $ 1,020    $ 1,020

Other guarantees

     2,649      224      2,873
                    

Total

   $ 2,649    $ 1,244    $ 3,893
                    

 

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

Financial Strength

On December 31, 2005, unused credit lines for short-term financing totaled approximately $5.4 billion (note 5 on page 58).

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 87 years.

 

     2005     2004     2003  

Fixed-charge coverage ratio (times)

   50.2     36.1     30.8  

Debt to capital (percent)

   6.5     7.3     9.3  

Net debt to capital (percent) (1)

   (22.0 )   (10.7 )   (1.2 )

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 (28.3) percent for 2005.

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.

The Corporation makes limited use of derivative instruments, which are discussed in Risk Management on page 41 and note 11 on page 62.

Litigation and Other Contingencies

As discussed in note 14 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 and paid. All of the punitive damage claims were consolidated in the civil trial that began in 1994. The first judgment from the United States District Court for the District of Alaska in the amount of $5 billion was vacated by the United States Court of Appeals for the Ninth Circuit as being excessive under the Constitution. The second judgment in the amount of $4 billion was vacated by the Ninth Circuit panel without argument and sent back for the District Court to reconsider in light of the recent U.S. Supreme Court decision in Campbell v. State Farm. The most recent District Court judgment for punitive damages was for $4.5 billion plus interest and was entered in January 2004. ExxonMobil and the plaintiffs have appealed this decision to the Ninth Circuit. The Corporation has posted a $5.4 billion letter of credit. Oral arguments were held before the Ninth Circuit on January 27, 2006. Management believes that the likelihood of the judgment being upheld is remote. While it is reasonably possible that a liability may have been incurred from the Exxon Valdez grounding, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability.

        In December 2000, a jury in the 15th Judicial Circuit Court of 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 in May 2001. In December 2002, the Alabama Supreme Court vacated the $3.5 billion jury verdict. The case was retried and in November 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. In March 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 to the Alabama Supreme Court. 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. In May 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. 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.

        In 2001, a Louisiana state court jury awarded compensatory damages of $56 million and punitive damages of $1 billion to a landowner for damage caused by a third party that leased the property from the landowner. The third party provided pipe cleaning and storage services for the Corporation and other entities. The Louisiana Fourth Circuit Court of Appeals reduced the punitive damage award to $112 million in 2005. The Corporation appealed this decision to the Louisiana Supreme Court as it continues to believe that these judgments should be substantially reduced on legal and constitutional grounds. While it is reasonably possible that a liability may have been incurred, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability.

 

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In Allapattah v. Exxon, a jury in the United States District Court for the Southern District of Florida determined in 2001 that a class of Exxon dealers between March 1983 and August 1994 had been overcharged for gasoline. In June 2003, the Eleventh Circuit Court of Appeals affirmed the judgment and in March 2004, denied a petition for Rehearing En Banc. In October 2004, the U.S. Supreme Court granted review 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. In light of the Supreme Court’s decision to grant review of only part of ExxonMobil’s appeal, the Corporation took an after-tax charge of $550 million in the third quarter of 2004 reflecting the estimated liability, after considering potential set-offs and defenses for the claims under review by the Supreme Court. In June 2005, the Supreme Court granted the District Court the right to hear the claims of all class members and the Corporation took an after-tax charge of $200 million. Class counsel and ExxonMobil are seeking court approval of a settlement of $1,075 million, pre-tax that would essentially finalize the Corporation’s financial obligation in the case; this obligation has been fully accrued. The trial court has preliminarily approved the settlement. Notice has been issued to the class and the final approval hearing will occur in April 2006.

Tax issues for 1986 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

 

     2005    2004
     U.S.    Non-U.S.    U.S.    Non-U.S.
     (millions of dollars)

Upstream (1)

   $ 2,142    $ 12,328    $ 1,922    $ 9,793

Downstream

     753      1,742      775      1,630

Chemical

     243      411      262      428

Other

     80           66      9
                           

Total

   $ 3,218    $ 14,481    $ 3,025    $ 11,860
                           

 

(1) Exploration expenses included.

Capital and exploration expenditures in 2005 were $17.7 billion, reflecting the Corporation’s continued active investment program. The Corporation expects spending to continue in this range for the next several years. Actual spending could vary depending on progress of individual projects.

Upstream spending was up 24 percent to $14.5 billion in 2005, from $11.7 billion in 2004, as a result of higher spending in growth areas such as Russia, the Caspian, Qatar and West Africa. In addition, spending in the U.S., Australia and the North Sea was also higher. During the past three years, Upstream capital and exploration expenditures averaged $12.7 billion. 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 and exploration expenditures are not tracked by the undeveloped and developed proved reserve categories. Capital investments in the Downstream totaled $2.5 billion in 2005, up $0.1 billion from 2004. Chemical capital expenditures were essentially unchanged from 2004.

TAXES

 

     2005     2004     2003  
     (millions of dollars)  

Income taxes

   $ 23,302     $ 15,911     $ 11,006  

Excise taxes

     30,742       27,263       23,855  

All other taxes and duties

     44,571       43,605       40,107  
                        

Total

   $ 98,615     $ 86,779     $ 74,968  
                        

Total effective tax rate

     41.4 %     40.3 %     36.4 %

2005

Income, excise and all other taxes totaled $98.6 billion in 2005, an increase of $11.8 billion or 14 percent from 2004. Income tax expense, both current and deferred, was $23.3 billion, $7.4 billion higher than 2004, reflecting higher pre-tax income in 2005. The effective tax rate was 41.4 percent in 2005, compared to 40.3 percent in 2004. 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 $75.3 billion in 2005 increased $4.4 billion from 2004, reflecting higher prices and foreign exchange effects.

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 2003. 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.

 

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

ASSET RETIREMENT OBLIGATIONS AND ENVIRONMENTAL COSTS

Asset Retirement Obligations

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 ($165 million for 2005). Over time, the liabilities are accreted for the increase in their present value, with this effect included in expenses ($208 million in 2005). Payments made for asset retirement obligations in 2005 were $193 million, and the ending balance of the obligations recorded on the balance sheet at December 31, 2005, totaled $3,568 million.

Environmental Costs

 

     2005    2004
     (millions of dollars)

Capital expenditures

   $ 1,240    $ 1,073

Included in expenses

     2,089      1,781
             

Total

   $ 3,329    $ 2,854
             

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 fuels as well as projects to reduce nitrogen oxide and sulfur oxide emissions. ExxonMobil’s 2005 worldwide environmental costs for all such preventative and remediation steps were about $3.3 billion, of which $1.2 billion were capital expenditures and $2.1 billion were included in expenses. The total cost for such activities is expected to remain in this range in 2006 and 2007 (with capital expenditures approximately 35 percent of the total).

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 or financial condition. Provisions made in 2005 for environmental liabilities were $487 million ($340 million in 2004), included in the $2.1 billion of 2005 expenses noted above, and the balance sheet reflects accumulated liabilities of $849 million as of December 31, 2005, and $643 million as of December 31, 2004.

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

 

Worldwide Average Realizations (1)    2005    2004    2003

Crude oil and NGL ($/barrel)

   $ 48.23    $ 34.76    $ 26.66

Natural gas ($/kcf)

     5.96      4.48      3.98

 

(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 varied. In the Upstream, based on the 2005 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.

 

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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 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, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivative instruments to mitigate the impact of such changes. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. The Corporation’s limited derivative activities pose no material credit or market risks to ExxonMobil’s operations, financial condition or liquidity. Note 11 on page 62 summarizes the fair value of derivatives outstanding at year-end and the gains or losses that have been recognized in net income.

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 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. The Corporation’s cash balances exceeded total debt at year-end 2005 and 2004.

The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in exchange rates on ExxonMobil’s geographically and functionally diverse operations are varied and often offsetting in amount. The Corporation makes limited use of currency exchange contracts, commodity forwards, swaps and futures contracts to mitigate the impact of changes in currency values and commodity prices. Exposures related to the Corporation’s limited use of the above contracts are 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.

RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS

Share-based Payment

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 requisite service 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 for the Corporation as of January 1, 2006, for awards granted or modified after that date and for awards granted prior to that date that have not vested. 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 stock option awards have vested. FAS 123R will therefore not materially change the Corporation’s existing accounting practices or the amount of share-based compensation recognized in earnings.

        The cumulative compensation expense associated with share-based payments made in 2005, 2004 and 2003 has been recognized in the income statement using the “nominal vesting period approach.” The full cost of awards given to employees who have retired before the end of the vesting period has been expensed. The use of a “non-substantive vesting period approach” based on the retirement eligibility age, would not be significantly different from the nominal vesting period approach. The non-substantive vesting period approach will be applicable to grants made after the adoption of FAS 123R on January 1, 2006.

Accounting for Purchases and Sales of Inventory with the Same Counterparty

At its September 2005 meeting, the Emerging Issues Task Force (EITF) reached a consensus on 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 exchanges measured at the book value of the item sold. The EITF concluded that purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another should be combined and recorded as exchanges measured at the book value of the item sold.

The Corporation records in revenues certain crude oil, natural gas, petroleum product and chemical sales where the Corporation contemporaneously negotiated purchases with the same counterparty. The purchases are recorded in crude oil and product purchases. These transactions are commonly called “buy/sell transactions” and are used to ensure that the right crude oil is available to the Corporation’s refineries at the right time and that appropriate products are available

 

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

to meet customer demand. The Corporation’s accounting treatment for these buy/sell transactions is consistent with long standing industry practice. The EITF consensus will result in the Corporation’s accounts “Sales and other operating revenue” and “Crude oil and product purchases” on the Consolidated Statement of Income being reduced by associated amounts with no impact on net income. All operating segments will be affected by this change, but the largest impacts are in the Downstream. The EITF consensus will become effective beginning no later than the second quarter of 2006.

The purchase/sale amounts included in revenue for 2005, 2004 and 2003 are shown in note 1 on page 52.

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 for calculating unit-of-production depreciation rates and for evaluating 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 include probable reserves. Probable reserves are reserves that are more 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, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. 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 company reserves), indicating that proved reserves are consistently moved from undeveloped to developed status. 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 and 2005 reserves on the basis of December 31 prices and costs (“year-end prices”).

        The use of year-end prices for reserves estimation introduces short-term price volatility into the process since annual adjustments are 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.

        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, or (3) changes to underlying price assumptions used in the determination of reserves. 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

 

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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.

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. Trigger events for impairment evaluation 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 operating losses.

In general, the Corporation does not view temporarily low oil prices as a trigger 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 risk-assessed operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. 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 76 to 85. The standardized measure of discounted future cash flows on pages 84 and 85 is based on the year-end 2005 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 exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Assessing whether a project has made sufficient progress is a subjective area and requires careful consideration of the relevant facts and circumstances. The facts and circumstances that support continued capitalization of suspended wells as of year-end 2005 are disclosed in note 2 to the financial statements on page 55.

 

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

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 6 on page 59. 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 its 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 of 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 15, pages 70 to 73, 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.

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 2005 was 9.0 percent. This compares to an actual rate of return over the past decade of 11 percent. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected 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 $95 million before tax.

 

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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.

Litigation and Other Contingencies

A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits and tax disputes. These are summarized on pages 38 and 39, and are also included in note 14 on pages 68 and 69.

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. Payments have not had a materially adverse effect on operations or financial condition. 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, include Malaysia, Indonesia, Angola, Nigeria, Equatorial Guinea, Russia 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 financial officer, and principal accounting 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, 2005.

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005, was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

 

LOGO   LOGO   LOGO

Rex W. Tillerson

 

Donald D. Humphreys

 

Patrick T. Mulva

Chief Executive Officer

 

Sr. Vice President and Treasurer

 

Vice President and Controller

 

(Principal Financial Officer)

 

(Principal Accounting Officer)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

LOGO

To the Shareholders of Exxon Mobil Corporation:

We have completed integrated audits of Exxon Mobil Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 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 48 to 75 present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, 2005, and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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 8 to the consolidated financial statements, the Corporation changed its method of accounting for asset retirement obligations in 2003.

 

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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, 2005, 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, 2005, 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, 2006

 

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CONSOLIDATED STATEMENT OF INCOME

 

     Note
Reference
Number
   2005    2004    2003
          (millions of dollars)

Revenues and other income

           

Sales and other operating revenue (1) (2)

      $ 358,955    $ 291,252    $ 237,054

Income from equity affiliates

   6      7,583      4,961      4,373

Other income

        4,142      1,822      5,311
                       

Total revenues and other income

      $ 370,680    $ 298,035    $ 246,738
                       

Costs and other deductions

           

Crude oil and product purchases

      $ 185,219    $ 139,224    $ 107,658

Production and manufacturing expenses

        26,819      23,225      21,260

Selling, general and administrative expenses

        14,402      13,849      13,396

Depreciation and depletion

        10,253      9,767      9,047

Exploration expenses, including dry holes

        964      1,098      1,010

Interest expense

        496      638      207

Excise taxes (1)

   17      30,742      27,263      23,855

Other taxes and duties

   17      41,554      40,954      37,645

Income applicable to minority and preferred interests

        799      776      694
                       

Total costs and other deductions

      $ 311,248    $ 256,794    $ 214,772
                       

Income before income taxes

      $ 59,432    $ 41,241    $ 31,966

Income taxes

   17      23,302      15,911      11,006
                       

Income from continuing operations

      $ 36,130    $ 25,330    $ 20,960

Cumulative effect of accounting change, net of income tax

        —        —        550
                       

Net income

      $ 36,130    $ 25,330    $ 21,510
                       

Net income per common share (dollars)

   10         

Income from continuing operations

      $ 5.76    $ 3.91    $ 3.16

Cumulative effect of accounting change, net of income tax

        —        —        0.08
                       

Net income

      $ 5.76    $ 3.91    $ 3.24
                       

Net income per common share – assuming dilution (dollars)

   10         

Income from continuing operations

      $ 5.71    $ 3.89    $ 3.15

Cumulative effect of accounting change, net of income tax

        —        —        0.08
                       

Net income

      $ 5.71    $ 3.89    $ 3.23
                       

 

(1) Sales and other operating revenue includes excise taxes of $30,742 million for 2005, $27,263 million for 2004 and $23,855 million for 2003.

 

(2) Sales and other operating revenue includes $30,810 million for 2005, $25,289 million for 2004 and $20,936 million for 2003 for purchases/sales contracts with the same counterparty. Associated costs are included in crude oil and product purchases. See note 1 on page 52.

The information on pages 52 through 75 is an integral part of these statements.

 

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CONSOLIDATED BALANCE SHEET

 

     Note
Reference
Number
   Dec. 31
2005
    Dec. 31
2004
 
          (millions of dollars)  

Assets

       

Current assets

       

Cash and cash equivalents

      $ 28,671     $ 18,531  

Cash and cash equivalents – restricted

   3, 14      4,604       4,604  

Notes and accounts receivable, less estimated doubtful amounts

   5      27,484       25,359  

Inventories

       

Crude oil, products and merchandise

   3      7,852       8,136  

Materials and supplies

        1,469       1,351  

Prepaid taxes and expenses

        3,262       2,396  
                   

Total current assets

      $ 73,342     $ 60,377  

Investments and advances

   7      20,592       18,404  

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

   8      107,010       108,639  

Other assets, including intangibles, net

        7,391       7,836  
                   

Total assets

      $ 208,335     $ 195,256  
                   

Liabilities

       

Current liabilities

       

Notes and loans payable

   5    $ 1,771     $ 3,280  

Accounts payable and accrued liabilities

   5      36,120       31,763  

Income taxes payable

        8,416       7,938  
                   

Total current liabilities

      $ 46,307     $ 42,981  

Long-term debt

   12      6,220       5,013  

Annuity reserves

   15      10,220       10,850  

Accrued liabilities

        6,434       6,279  

Deferred income tax liabilities

   17      20,878       21,092  

Deferred credits and other long-term obligations

        3,563       3,333  

Equity of minority and preferred shareholders in affiliated companies

        3,527       3,952  
                   

Total liabilities

      $ 97,149     $ 93,500  
                   

Commitments and contingencies

   14     

Shareholders’ equity

       

Benefit plan related balances

      $ (1,266 )   $ (1,014 )

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

        5,743       5,067  

Earnings reinvested

        163,335       134,390  

Accumulated other nonowner changes in equity

       

Cumulative foreign exchange translation adjustment

        979       3,598  

Minimum pension liability adjustment

        (2,258 )     (2,499 )

Unrealized gains/(losses) on stock investments

        —         428  

Common stock held in treasury (1,886 million shares in 2005 and 1,618 million shares in 2004)

        (55,347 )     (38,214 )
                   

Total shareholders’ equity

      $ 111,186     $ 101,756  
                   

Total liabilities and shareholders’ equity

      $ 208,335     $ 195,256  
                   

The information on pages 52 through 75 is an integral part of these statements.

 

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CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

 

     Note
Reference
Number
   2005     2004     2003
        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

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

Restricted stock award

        (613 )       (555 )       (358 )  

Amortization

        356         173         107    

Other

        5         2         67    
                                 

At end of year

      $ (1,266 )     $ (1,014 )     $ (634 )  
                                 

Common stock

               

At beginning of year

        5,067         4,468         4,217    

Issued

        —           —           —      

Other

        676         599         251    
                                 

At end of year

      $ 5,743       $ 5,067       $ 4,468    
                                 

Earnings reinvested

               

At beginning of year

        134,390         115,956         100,961    

Net income for the year

        36,130     $ 36,130       25,330     $ 25,330       21,510     $ 21,510

Dividends – common shares

        (7,185 )       (6,896 )       (6,515 )  
                                 

At end of year

      $ 163,335       $ 134,390       $ 115,956    
                                 

Accumulated other nonowner changes in equity

               

At beginning of year

        1,527         (514 )       (6,054 )  

Foreign exchange translation adjustment

        (2,619 )     (2,619 )     2,177       2,177       4,436       4,436

Minimum pension liability adjustment

   15      241       241       (53 )     (53 )     514       514

Unrealized gains/(losses) on stock investments

        —         —         (83 )     (83 )     590       590

Reclassification adjustment for gain on sale of stock investment included in net income

        (428 )     (428 )     —         —         —         —  
                                 

At end of year

      $ (1,279 )     $ 1,527       $ (514 )  
                                                 

Total

        $ 33,324       $ 27,371       $ 27,050
                               

Common stock held in treasury

               

At beginning of year

        (38,214 )       (29,361 )       (24,077 )  

Acquisitions, at cost

        (18,221 )       (9,951 )       (5,881 )  

Dispositions

        1,088         1,098         597    
                                 

At end of year

      $ (55,347 )     $ (38,214 )     $ (29,361 )  
                                 

Shareholders’ equity at end of year

      $ 111,186       $ 101,756       $ 89,915    
                                 
          Share Activity      
          2005           2004           2003      
          (millions of shares)      

Common stock

               

Issued

               

At beginning of year

        8,019         8,019         8,019    

Issued

        —           —           —      
                                 

At end of year

        8,019         8,019         8,019    
                                 

Held in treasury

               

At beginning of year

        (1,618 )       (1,451 )       (1,319 )  

Acquisitions

        (311 )       (218 )       (163 )  

Dispositions

        43         51         31    
                                 

At end of year

        (1,886 )       (1,618 )       (1,451 )  
                                 

Common shares outstanding at end of year

        6,133         6,401         6,568    
                                 

The information on pages 52 through 75 is an integral part of these statements.

 

50


Table of Contents
Index to Financial Statements

CONSOLIDATED STATEMENT OF CASH FLOWS

 

     Note
Reference
Number
   2005     2004     2003  
          (millions of dollars)  

Cash flows from operating activities

         

Net income

         

Accruing to ExxonMobil shareholders

      $ 36,130     $ 25,330     $ 21,510  

Accruing to minority and preferred interests

        799       776       694  

Cumulative effect of accounting change, net of income tax

        —         —         (550 )

Adjustments for noncash transactions

         

Depreciation and depletion

        10,253       9,767       9,047  

Deferred income tax charges/(credits)

        (429 )     (1,134 )     1,827  

Annuity provisions

        254       886       (1,489 )

Accrued liability provisions

        398       806       264  

Dividends received greater than/(less than) equity in current earnings of equity companies

        (734 )     (1,643 )     (402 )

Changes in operational working capital, excluding cash and debt

         

Reduction/(increase) – Notes and accounts receivable

        (3,700 )     (472 )     (1,286 )

– Inventories

        (434 )     (223 )     (100 )

– Prepaid taxes and expenses

        (7 )     11       42  

Increase/(reduction) – Accounts and other payables

        7,806       6,333       1,130  

Net (gain) on asset sales and Ruhrgas transaction

   4      (1,980 )     (268 )     (2,461 )

All other items – net

        (218 )     382       272  
                           

Net cash provided by operating activities

      $ 48,138     $ 40,551     $ 28,498  
                           

Cash flows from investing activities

         

Additions to property, plant and equipment

      $ (13,839 )   $ (11,986 )   $ (12,859 )

Sales of subsidiaries, investments and property, plant and equipment

   4      6,036       2,754       2,290  

Increase in restricted cash and cash equivalents

   3, 14      —         (4,604 )     —    

Additional investments and advances

        (2,810 )     (2,287 )     (809 )

Collection of advances

        343       1,213       536  
                           

Net cash used in investing activities

      $ (10,270 )   $ (14,910 )   $ (10,842 )
                           

Cash flows from financing activities

         

Additions to long-term debt

      $ 195     $ 470     $ 127  

Reductions in long-term debt

        (81 )     (562 )     (914 )

Additions to short-term debt

        377       450       715  

Reductions in short-term debt

        (687 )     (2,243 )     (1,730 )

Additions/(reductions) in debt with less than 90-day maturity

        (1,306 )     (66 )     (322 )

Cash dividends to ExxonMobil shareholders

        (7,185 )     (6,896 )     (6,515 )

Cash dividends to minority interests

        (293 )     (215 )     (430 )

Changes in minority interests and sales/(purchases) of affiliate stock

        (681 )     (215 )     (247 )

Common stock acquired

        (18,221 )     (9,951 )     (5,881 )

Common stock sold

        941       960       434