10-K 1 d10k.htm FORM 10-K Form 10-K
Table of Contents
Index to Financial Statements

2006


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, 2006

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 (5,693,398,774 shares
outstanding at January 31, 2007)

   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.      

 

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, 2006, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $61.35 on the New York Stock Exchange composite tape, was in excess of $364 billion.

 

Documents Incorporated by Reference:

    Proxy Statement for the 2007 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, 2006

 

TABLE OF CONTENTS

 

     Page
Number


PART I
Item 1.   

Business

   1
Item 1A.   

Risk Factors

   2
Item 1B.   

Unresolved Staff Comments

   4
Item 2.   

Properties

   4
Item 3.   

Legal Proceedings

   20
Item 4.   

Submission of Matters to a Vote of Security Holders

   21
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]    22
PART II
Item 5.   

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

   23
Item 6.   

Selected Financial Data

   24
Item 7.   

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

   24
Item 7A.   

Quantitative and Qualitative Disclosures About Market Risk

   24
Item 8.   

Financial Statements and Supplementary Data

   24
Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure    25
Item 9A.    Controls and Procedures    25
Item 9B.    Other Information    25
PART III
Item 10.   

Directors, Executive Officers and Corporate Governance

   26
Item 11.   

Executive Compensation

   26
Item 12.   

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

   26
Item 13.   

Certain Relationships and Related Transactions, and Director Independence

   27
Item 14.   

Principal Accounting Fees and Services

   27
PART IV
Item 15.   

Exhibits, Financial Statement Schedules

   27
Financial Section    29
Signatures    94
Index to Exhibits    96
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 most other countries of the world. 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 air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels as well as projects to reduce nitrogen oxide and sulfur oxide emissions and expenditures for asset retirement obligations. ExxonMobil’s 2006 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $3.2 billion, of which $1.1 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 2007 and 2008 (with capital expenditures approximately 40 percent of the total).

 

Operating data and industry segment information for the Corporation are contained in the Financial Section of this report under the following: “Quarterly Information”, “Note 17: Disclosures about Segments and Related Information” and “Operating Summary”. Information on oil and gas reserves is contained in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report. Information on Company-sponsored research and development activities is contained in “Note 3: Miscellaneous Financial Information” of the Financial Section of this report.

 

The number of regular employees was 82.1 thousand, 83.7 thousand and 85.9 thousand at years ended 2006, 2005 and 2004, 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 24.3 thousand, 22.4 thousand and 19.3 thousand at years ended 2006, 2005 and 2004, 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

 

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Index to Financial Statements

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.

 

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 and Legal 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 and legal factors including:

 

   

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

 

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Index to Financial Statements
   

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

 

   

laws and regulations related to environmental or energy security matters, including those addressing alternative energy sources and the risks of global climate change;

 

   

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 the “Market Risks, Inflation and Other Uncertainties” portion of the Financial Section of this report for discussion of the impact of market risks, inflation and other uncertainties.

 

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

 

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Index to Financial Statements

 

Item 1B.     Unresolved Staff Comments.

 

None.

 

Item 2.    Properties.

 

Part of the information in response to this item and to the Securities Exchange Act Industry Guide 2 is contained in “Note 8: Property, Plant and Equipment and Asset Retirement Obligations” and in the “Supplemental Information on Oil and Gas Exploration and Production Activities,” both included in the Financial Section of this report.

 

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 2006

 

Estimated proved reserves are shown in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report. No major discovery or other favorable or adverse event has occurred since December 31, 2006, 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 the “Standardized Measure of Discounted Future Cash Flows” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion 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 in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report for the year ended December 31, 2006. The Corporation has reported 2005 and 2006 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

   1,884    962    748    2,089    1,287    791    433    8,194
     (billions of cubic feet)

Natural gas

   12,049    1,517    7,089    986    9,583    789    467    32,480
     (millions of oil-equivalent barrels)

Oil-equivalent basis

   3,892    1,215    1,930    2,253    2,884    922    511    13,607

 

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Index to Financial Statements

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

 

     Year-End 2006

   Year-End 2005

     Developed

   Undeveloped

   Developed

   Undeveloped

     (millions of oil-equivalent barrels)

Consolidated Subsidiaries

                   

United States

   3,013    879    3,411    984

Canada

   921    294    862    254

Europe

   1,448    482    1,711    572

Africa

   1,416    837    1,281    1,171

Asia Pacific/Middle East

   2,070    814    1,475    253

Russia/Caspian

   183    739    93    751

South America

   252    259    279    275
    
  
  
  

Total

   9,303    4,304    9,112    4,260
    
  
  
  

Equity Companies

                   

United States

   329    84    345    91

Europe

   1,675    429    1,713    468

Asia Pacific/Middle East

   1,948    2,995    1,938    2,629

Russia/Caspian

   679    364    713    373
    
  
  
  

Total

   4,631    3,872    4,709    3,561
    
  
  
  

 

In the preceding reserves information, and in the reserves tables in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion 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 view 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 2007-2011. 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, 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 amount recovered 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 2006, 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 2005, 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,

 

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Index to Financial Statements

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 2005 exceeds five percent.

 

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

 

Reference is made to the “Results of Operations” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion 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 in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion 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 in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion 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.

 

4.    Gross and Net Productive Wells

 

     Year-End 2006

   Year-End 2005

     Oil

   Gas

   Oil

   Gas

     Gross

   Net

   Gross

   Net

   Gross

   Net

   Gross

   Net

United States

   28,139    10,644    9,059    5,468    28,288    10,865    9,187    5,441

Canada

   5,662    4,975    5,857    3,058    5,967    5,214    6,115    2,991

Europe

   1,780    528    1,300    509    1,872    590    1,294    512

Africa

   823    348    12    5    674    277    14    6

Asia Pacific/Middle East

   2,191    587    267    184    1,991    532    259    180

Russia/Caspian

   82    17          77    16    2    1

South America

   154    64    85    30    154    64    89    30
    
  
  
  
  
  
  
  

Total

   38,831    17,163    16,580    9,254    39,023    17,558    16,960    9,161
    
  
  
  
  
  
  
  

 

The numbers of wells operated at year-end 2006 were 16,914 gross wells and 13,988 net wells. At year-end 2005, the numbers of operated wells were 17,351 gross wells and 14,028 net wells.

 

5.    Gross and Net Developed Acreage

 

     Year-End 2006

   Year-End 2005

     Gross

   Net

   Gross

   Net

     (thousands of acres)

United States

   9,045    5,178    9,194    5,260

Canada

   4,812    2,099    4,869    2,238

Europe

   10,678    4,418    11,303    4,687

Africa

   1,842    717    1,497    545

Asia Pacific/Middle East

   8,210    1,655    7,876    1,570

Russia/Caspian

   531    116    531    116

South America

   690    232    690    232
    
  
  
  

Total

   35,808    14,415    35,960    14,648
    
  
  
  

 

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

 

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6.    Gross and Net Undeveloped Acreage

 

     Year-End 2006

   Year-End 2005

     Gross

   Net

   Gross

   Net

     (thousands of acres)

United States

   9,917    6,062    10,388    6,413

Canada

   10,659    4,785    10,816    4,822

Europe

   8,089    2,727    8,782    2,778

Africa

   39,306    24,075    49,328    29,048

Asia Pacific/Middle East

   13,466    7,462    7,114    3,797

Russia/Caspian

   2,181    449    2,561    569

South America

   20,803    17,229    26,552    19,513
    
  
  
  

Total

   104,421    62,789    115,541    66,940
    
  
  
  

 

        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.

 

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

 

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 Mining Law, effective January 1, 2003, exploration and production licenses for both onshore and offshore areas are issued for a period as explicitly defined in the license. The term is based on the period of time necessary to perform the activities for which the license is issued. License conditions are stipulated in the Mining Law.

 

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Production rights granted prior to January 1, 2003, remain subject to their existing terms, and differ slightly for onshore and offshore areas. Onshore production licenses issued prior to 1988 were indefinite; from 1988 they were issued for a period as explicitly defined in the license, ranging from 35 to 45 years. Offshore production licenses issued before 1976 were issued for a fixed period of 40 years; from 1976 they were again issued for a period as explicitly defined in the license, ranging from 15 to 40 years.

 

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 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 a final term of 18 years. There is a mandatory relinquishment of 50-percent of the 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.

 

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Equatorial Guinea

 

Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines, Industry 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. A new Hydrocarbons Law was enacted in November 2006. Under the new law, the exploration terms for new production sharing contracts are expected to be four to five years with a maximum of two one-year extensions, unless the Ministry agrees otherwise.

 

Nigeria

 

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

 

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

 

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

 

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

 

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

 

ASIA PACIFIC / MIDDLE EAST

 

Australia

 

Exploration and production activities are conducted offshore and are governed by Federal legislation. Exploration permits are granted for an initial term of 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 July 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter “indefinitely”, i.e., for

 

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Index to Financial Statements

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). Effective from July 1998, new production licenses are granted “indefinitely”.

 

Indonesia

 

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

 

Japan

 

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

 

Malaysia

 

Exploration and production activities are governed by production sharing contracts negotiated with the national oil company. The more recent contracts have an overall term of 24 to 38 years, depending on water depth, 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 within the maximum possible retention time of 15 years. Petroleum Retention licenses are granted for five-year terms, and may be extended, at the Minister’s discretion, twice for the 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.

 

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Index to Financial Statements

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 for the major onshore oilfields 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. An interest in the Upper Zakum field, a major offshore field, was acquired effective as of January 1, 2006, for a term expiring March 9, 2026, on fiscal terms consistent with the Company’s existing interests in Abu Dhabi.

 

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 was six years followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is for 20 years from the date of declaration of commerciality 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.

 

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Index to Financial Statements

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. The Venezuelan Government has indicated a desire to increase ownership by the National Oil Company (PdVSA) to greater than 50 percent in the projects covered by these agreements and to make other changes to applicable fiscal terms.

 

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8.    Number of Net Productive and Dry Wells Drilled

 

     2006

   2005

   2004

A. Net Productive Exploratory Wells Drilled

              

United States

   10    13    11

Canada

   3    1    2

Europe

   2    4    3

Africa

   4    5    2

Asia Pacific/Middle East

   2    1    2

Russia/Caspian

         1

South America

        
    
  
  

Total

   21    24    21
    
  
  

B. Net Dry Exploratory Wells Drilled

              

United States

   5    5    6

Canada

         4

Europe

   2    1    1

Africa

   4    5    4

Asia Pacific/Middle East

      1   

Russia/Caspian

      1   

South America

   1      
    
  
  

Total

   12    13    15
    
  
  

C. Net Productive Development Wells Drilled

              

United States

   552    537    568

Canada

   371    263    466

Europe

   22    19    24

Africa

   64    61    64

Asia Pacific/Middle East

   25    50    35

Russia/Caspian

   5    7    4

South America

   2    9    3
    
  
  

Total

   1,041    946    1,164
    
  
  

D. Net Dry Development Wells Drilled

              

United States

   5    8    13

Canada

   1    2    2

Europe

   4    2    2

Africa

   1      

Asia Pacific/Middle East

      2    1

Russia/Caspian

        

South America

        
    
  
  

Total

   11    14    18
    
  
  

Total number of net wells drilled

   1,085    997    1,218
    
  
  

 

9.    Present Activities

 

A. Wells Drilling

 

     Year-End 2006

   Year-End 2005

     Gross

   Net

   Gross

   Net

United States

   214    109    148    84

Canada

   223    182    148    94

Europe

   55    11    46    12

Africa

   50    19    53    21

Asia Pacific/Middle East

   49    14    70    24

Russia/Caspian

   33    6    38    8

South America

   3    1    3    1
    
  
  
  

Total

   627    342    506    244
    
  
  
  

 

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B. Review of Principal Ongoing Activities in Key Areas

 

During 2006, 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 2006. At year-end 2006, ExxonMobil’s acreage totaled 11.2 million net acres, of which 2.6 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

 

During 2006, 543.9 net exploration and development wells were completed in the inland lower 48 states and 3.0 net development wells were completed offshore in the Pacific. Tight gas development continues in the Piceance Basin of Colorado. Participation in Alaska production and development continued and a total of 14.6 net development wells were drilled. On Alaska’s North Slope, activity continued on the Western Region Development Project (primarily the Orion field) with development drilling and engineering design for facility expansions.

 

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2006 was 2.4 million acres. A total of 10.9 net exploration and development wells were completed during the year. Installation and commissioning of the semi-submersible production and drilling vessel continued for the Thunder Horse development in 2006. Startup, delayed due to a listing incident and subsea manifolds that failed during testing, is anticipated to occur in 2008.

 

CANADA

 

ExxonMobil’s year-end 2006 acreage holdings totaled 6.9 million net acres, of which 3.1 million net acres were offshore. A total of 375.0 net exploration and development wells were completed during the year. In eastern Canada, work continued on the Sable Compression project. Hook-up and commissioning of the compression platform was completed at Sable in the fourth quarter of 2006.

 

EUROPE

 

France

 

ExxonMobil divested its oil and gas exploration and production assets in 2006.

 

Germany

 

A total of 2.3 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2006, with 4.6 net development and exploration wells drilled during the year.

 

Netherlands

 

ExxonMobil’s net interest in licenses totaled approximately 1.8 million acres at year-end 2006, 1.5 million acres onshore and 0.3 million acres offshore. A total of 3.6 net exploration and development wells were completed during the year. The offshore K17-FA field started up. The multi-year onshore

 

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project to renovate production clusters, install new compression to maintain capacity and extend field life continued.

 

Norway

 

ExxonMobil’s net interest in licenses at year-end 2006 totaled approximately 0.8 million acres, all offshore. ExxonMobil participated in 9.3 net exploration and development well completions in 2006. Production was initiated at Ringhorne East in March and Fram East in October. The Ormen Lange, Statfjord Late Life, Skarv, Volve, Tyrihans and Njord Gas Export projects are in progress.

 

United Kingdom

 

ExxonMobil’s net interest in licenses at year-end 2006 totaled approximately 1.9 million acres, all offshore. A total of 12.1 net exploration and development wells were completed during the year. The Cutter and Merganser projects commenced production during 2006. Other projects progressed in 2006 include Caravel and Starling.

 

AFRICA

 

Angola

 

ExxonMobil’s year-end 2006 acreage holdings totaled 0.7 million net offshore acres and 9.2 net exploration and development wells were completed during the year. On Block 15, development drilling continued on Kizomba A and Kizomba B. Development construction continued on the Marimba North project, which will tie-back to the Kizomba A FPSO. Planning for the Kizomba C development concluded and construction is fully underway. A block-wide 4D seismic acquisition program concluded at mid-year. On Block 17, the Dalia project started-up in December. Construction and development activities continued on the Rosa project.

 

Cameroon

 

ExxonMobil’s acreage totaled 0.3 million net offshore acres at year-end 2006.

 

Chad

 

ExxonMobil’s net year-end 2006 acreage holdings consisted of 3.3 million onshore acres, with 32.8 net exploration and development wells completed during the year. Production began from the Moundouli field.

 

Equatorial Guinea

 

ExxonMobil’s acreage totaled 0.3 million net offshore acres at year-end 2006, with 8.3 net development wells completed during the year.

 

Nigeria

 

ExxonMobil’s net acreage totaled 1.3 million offshore acres at year-end 2006, with 21.5 net exploration and development wells completed during the year. Several major project start-ups were executed in the year. The Yoho field (OML 104) full-field production platform started production in January 2006. The Erha Floating Production, Storage and Offloading (FPSO) vessel commenced production from the deepwater Erha field (OML 133) in March 2006. Production was initiated from the Erha North field (tie-back to the Erha FPSO) in September 2006. The ExxonMobil-operated East

 

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Area Additional Oil Recovery project started up in January 2006 and pipeline tie-ins continued throughout the year. This project positions Nigerian operations for a significant reduction in flaring in 2007. Detailed design and construction continued on the ExxonMobil-operated East Area Natural Gas Liquids II project. The Amenam-Kpono Phase 2 Gas project started up in late 2006.

 

ASIA PACIFIC / MIDDLE EAST

 

Australia

 

ExxonMobil’s net year-end 2006 acreage holdings totaled 1.4 million acres, all offshore. During 2006, a total of 5.8 net exploration and development wells were drilled.

 

Indonesia

 

At year-end 2006, ExxonMobil had 3.9 million net acres, 3.0 million acres offshore and 0.9 million acres onshore. Project activities commenced in mid-2006 on the Banyu Urip development in the Cepu Contract Area after the execution of commercial agreements and approval of the Plan of Development by the government of Indonesia.

 

Japan

 

ExxonMobil’s net offshore acreage was 36 thousand acres at year-end 2006.

 

Malaysia

 

ExxonMobil has interests in production sharing contracts covering 0.5 million net acres offshore Malaysia at year-end 2006. During the year, a total of 4.0 net exploration and development wells were completed. The Guntong E platform, part of the Guntong Hub development, started up in July 2006. Infill drilling wells were successfully completed at the Jerneh-A platform. Drilling activities are currently ongoing at Tabu-B and Angsi-C.

 

Papua New Guinea

 

A total of 0.5 million net onshore acres were held by ExxonMobil at year-end 2006, with 1.0 net development well 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, ExxonMobil’s Al Khaleej Gas (AKG) Phase 1 project supplied pipeline gas to domestic industrial customers. The AKG facilities add sales gas capacity of up to 750 mcfd (millions of cubic feet per day) and produced associated condensate and LPG (Liquid Petroleum Gas). The AKG Phase 2 project is planned to add sales gas capacity of up to 1,250 mcfd, while recovering associated condensate and LPG.

 

At the end of 2006, 60 (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 3 and AKG 2 projects. At year-end 2006, ExxonMobil had 1.1 million net acres, 1.0 million acres onshore and 0.1 million acres offshore. During 2006, 9.9 net development wells were completed.

 

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Qatar LNG capacity volumes at year-end included 9.7 MTA (millions of metric tons per annum) in QG trains 1-3 and a combined 20.7 MTA in RL I trains 1-2 and RL II trains 3-5. In November 2006 production commenced at RL II train 5, although offshore facilities were not completed at year-end 2006. Construction of QG II trains 4-5 will add planned capacity of 15.6 MTA when complete. In addition, construction of RL 3 trains 6-7 will add planned capacity of 15.6 MTA 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 train 3, and approximately 49 BCF/MT for QG II trains 4-5, RL II trains 4-5, and RL 3 trains 6-7.

 

Republic of Yemen

 

ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end 2006.

 

Thailand

 

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2006.

 

United Arab Emirates

 

In 2006, ExxonMobil acquired a 28 percent equity in the offshore Upper Zakum oil concession. The concession ends on March 9, 2026.

 

ExxonMobil’s net acreage in the Abu Dhabi oil concessions was 0.6 million acres at year-end 2006, 0.4 million acres onshore and 0.2 million acres offshore. During the year, a total of 6.4 net development and exploration wells were completed. The Northeast Bab Phase 1 new field development project was completed successfully.

 

RUSSIA / CASPIAN

 

Azerbaijan

 

At year-end 2006, ExxonMobil’s net acreage, located in the Caspian Sea offshore of Azerbaijan, totaled 60 thousand acres. At the Azeri-Chirag-Gunashli (ACG) field, 1.0 net development well was completed and production ramp-up continued. The second phase of full field development was initiated with the start-up of West Azeri in January 2006 followed by East Azeri in November 2006 with full-field oil production increased to 660 thousand barrels of oil per day (gross) by year-end. Seventy percent of the construction on the Phase 3 Deep Water Gunashli Project was complete at year-end, with production start up anticipated in 2008.

 

Kazakhstan

 

ExxonMobil’s net acreage totaled 0.2 million acres onshore and 0.2 million acres offshore at year-end 2006, with 1.4 net exploration and development wells completed during 2006. At Tengiz, construction of the 285 thousand barrels of oil per day (gross) expansion project continued through 2006. Engineering and construction of the initial phase of the Kashagan field continued during 2006.

 

Russia

 

ExxonMobil’s net acreage holdings at year-end 2006 were 0.1 million acres, all offshore. A total of 3.0 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 and continued through the third quarter 2006. Full-field production with crude oil export and domestic gas sales began in the fourth quarter 2006 and drilling activities are continuing. 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, a mainland terminal and an offshore loading buoy for shipment of oil by tanker.

 

SOUTH AMERICA

 

Argentina

 

ExxonMobil’s net acreage totaled 0.2 million onshore acres at year-end 2006, and there were 1.9 net development wells completed during the year.

 

Venezuela

 

ExxonMobil’s net year-end 2006 acreage holdings totaled 0.1 million onshore acres.

 

WORLDWIDE EXPLORATION

 

At year-end 2006, exploration activities were underway in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 37.4 million net acres were held at year-end 2006, and 2.0 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 oil 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 1.7 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 oil sands and produce synthetic crude oil from approved development areas on oil sands leases. Syncrude holds eight oil sands leases covering approximately 248,300 acres in the Athabasca Oil Sands Deposit which were issued by the Province of Alberta. The leases are automatically renewable as long as oil 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. The Base mine (lease 17) has now

 

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been mined out and only remnants are now being removed using trucks and shovels. In the 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 740,000 tons of oil sands a day, producing 150 million barrels of crude bitumen a year. This represents recovery capability of about 93 percent of the crude bitumen contained in the mined oil sands.

 

Crude bitumen extracted from oil sands is refined to a marketable hydrocarbon product through a combination of carbon removal in three 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 2006, this upgrading process yielded 0.849 barrels of synthetic crude oil per barrel of crude bitumen. In 2006 about 44 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 56 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 a 160 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. Recycled water is the primary water source, and incremental raw water is drawn, under license, from the Athabasca River. 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 $2.9 billion at year-end 2006.

 

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, 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. In active mining areas, the approximate well spacing is 400 feet (150 wells per section) and in future mining areas, the well spacing is approximately 1,150 feet (20 wells per section). Proven reserves include the operating Base and North mines and the Aurora mine. In accordance with the approved mining plan, there are an estimated 1,845 million tons of extractable oil 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 4,580 million tons of extractable oil 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 2006 was equivalent to 718 million barrels of synthetic crude oil. Imperial’s reserve assessment uses a 6 percent and 7 percent bitumen grade cut-off for the North mine and Aurora mine respectively, a 90 percent overall extraction recovery, a 97 percent mining dilution factor and an 88 percent upgrading yield.

 

In 2001, the Syncrude owners endorsed a further development of the Syncrude resource in the area and expansion of the upgrading facilities. The Syncrude Aurora 2 and Upgrader Expansion 1 project adds a remote mining train and expands the central processing and upgrading plant. This increased upgrading capacity came on stream in 2006 and increased production capacity to 355 thousand barrels of synthetic crude oil per day (gross). Additional mining trains in the North mine and Aurora mine were also completed in 2005. There are no approved plans for major future expansion projects.

 

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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, 2006

   208     530     738  

Revision of previous estimate

       1     1  

Production

   (9 )   (12 )   (21 )
    

 

 

December 31, 2006

   199     519     718  
    

 

 


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

 

Syncrude Operating Statistics (total operation)

 

     2006

   2005

   2004

   2003

   2002

 

Operating Statistics

                          

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

   128.2    97.1    100.3    109.2    102.0  

Mined overburden to oil sands ratio(1)

   1.18    1.02    0.94    1.15    1.05  

Oil sands mined (millions of tons)

   195.5    168.0    188.0    168.0    172.1  

Average bitumen grade (weight percent)

   11.4    11.1    11.1    11.0    11.2  
    
  
  
  
  

Crude bitumen in mined oil sands (millions of tons)

   22.2    18.6    20.9    18.5    19.2  

Average extraction recovery (percent)

   90.3    89.1    87.3    88.6    89.9  
    
  
  
  
  

Crude bitumen production (millions of barrels)(2)

   111.6    94.2    103.3    92.3    97.8  

Average upgrading yield (percent)

   84.9    85.3    85.5    86.0    86.3  
    
  
  
  
  

Gross synthetic crude oil produced (millions of barrels)

   95.5    79.3    88.4    78.4    84.8  

ExxonMobil net share (millions of barrels)(3)

   21    19    22    19    21  

(1)   Includes pre-stripping of mine areas and reclamation volumes.
(2)   Crude bitumen production is equal to crude bitumen in mined oil 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.

 

As previously reported, the Puerto Rican Environmental Quality Board (“EQB”) issued an order on May 21, 2001, alleging that Esso Standard Oil Company (Puerto Rico) (“Esso”) failed to investigate and remediate alleged hydrocarbon contamination associated with underground storage tanks at a service station in Barranquitas, Puerto Rico. The EQB sought a penalty of $75.9 million. Esso filed a federal law suit challenging the constitutionality of the procedures used in the EQB administrative process related to the penalty assessment. In March 2005, the federal District Court in the suit concluded that the EQB proceeding was impermissibly biased against Esso and issued a preliminary injunction prohibiting the EQB from continuing its penalty hearing or imposing the $75.9 million penalty on Esso. On November 7, 2006, after granting Esso’s motion for summary judgment, the District Court issued a permanent injunction that similarly prohibits EQB actions with respect to the penalty proceeding. The EQB may appeal this decision.

 

20


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Index to Financial Statements

As previously disclosed, the New York State Department of Environmental Conservation (“NYSDEC”) issued a Notice of Hearing and complaint on March 24, 2004, alleging that ExxonMobil Oil Corporation in whole or in part is responsible for a discharge of 17 million gallons of petroleum prior to 1978 in connection with past operations at its Brooklyn terminal. The NYSDEC also alleged that the Brooklyn terminal had numerous spills after 1978, in violation of New York Navigation Law. The NYSDEC sought natural resource damages. On June 19, 2006, the NYSDEC referred the matter to the New York State Attorney General (“AG”). On November 30, 2006, the NYSDEC advised the Administrative Law Judge that it was withdrawing the pending administrative enforcement case, without prejudice. On February 8, 2007, the AG issued two notices of intent to sue ExxonMobil in connection with its remedial activities at the Brooklyn terminal site. The first notice relates to alleged violations under the Clean Water Act. The State indicates it will seek civil penalties and injunctive relief for allegedly ongoing, unpermitted discharges of pollutants by the company into Newtown Creek. The second notice relates to alleged violations of the Resource Conservation and Recovery Act (RCRA) as a result of solid or hazardous waste contamination of soils, groundwater, and the surface waters and sediments of Newtown Creek. This notice names ExxonMobil and four unrelated entities as potential parties and indicates the State is seeking injunctive relief.

 

In another previously reported matter, Mobil Pipe Line Company (“Mobil”) agreed in January 2007 to sign a Consent Assessment of Civil Penalty issued by the Pennsylvania Department of Environmental Protection (“PDEP”) on May 11, 2006, pursuant to the Pennsylvania Clean Streams Law. This Consent Assessment resolves PDEP’s allegations that Mobil discharged gasoline into the soil and groundwater in South Whitehall Township, Pennsylvania. The release allegedly occurred from a pipeline and also caused a fire beginning on February 1, 2005, and continuing until February 4, 2005. Mobil will pay a combined civil penalty and cost reimbursement amount of $122,000. This is full and final resolution of any existing or potential liability of Mobil to the PDEP for the incident at issue.

 

Regarding a previously disclosed matter, on January 26, 2007, ExxonMobil Oil Corporation and California’s Department of Toxic Substances Control (“DTSC”) signed a Consent Order settling allegations made by the DTSC in a Summary of Violations issued to the Torrance Refinery in December 2003. The DTSC had alleged that the refinery had discharged wastewater containing soluble selenium above one part per million to the sewer that leads to the county treatment facility in violation of California hazardous waste rules. The Consent Order calls for the refinery to comply with the hazardous waste regulations as they relate to its discharge into the sewer of wastewater containing selenium and calls for the following payments totaling $650,000: administrative penalty - $350,000; supplemental environmental project - $150,000; reimbursement of DTSC costs - $100,000; and payment to the Western States Project Training Fund - $50,000.

 

Refer to the relevant portions of “Note 15: Litigation and Other Contingencies” 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.

 


 

21


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Index to Financial Statements

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

 

Name


  Age as of
March 1,
2007


  Title (Held Office Since)

R. W. Tillerson

  54   Chairman of the Board (2006)

D. D. Humphreys

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

S. R. McGill

  64   Senior Vice President (2004)

J. S. Simon

  63   Senior Vice President (2004)

M. W. Albers

  50   President, ExxonMobil Development Company (2004)

A. T. Cejka

  55   Vice President (2004)

H. R. Cramer

  56   Vice President (1999)

M. J. Dolan

  53   Vice President (2004)

M. E. Foster

  63   Vice President (2004)

H. H. Hubble

  54   Vice President—Investor Relations and Secretary (2004)

G. L. Kohlenberger

  54   Vice President (2002)

C. W. Matthews

  62   Vice President and General Counsel (1995)

P. T. Mulva

  55   Vice President and Controller (2004)

S. D. Pryor

  57   Vice President (2004)

P. E. Sullivan

  63   Vice President and General Tax Counsel (1995)

A. P. Swiger

  50   Vice President (2006)

 

For at least the past five years, Messrs. Cramer, Humphreys, Kohlenberger, Matthews, McGill, Simon, Sullivan and Tillerson 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.

 

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, 2006.

 

Esso Exploration and Production Chad Inc.

   Albers and Swiger

Exxon Azerbaijan Caspian Sea Limited

   Swiger

Exxon Azerbaijan Limited

   Swiger

ExxonMobil Chemical Company

   Dolan and Pryor

ExxonMobil Development Company

   Albers and Foster

ExxonMobil Exploration Company

   Cejka

ExxonMobil Fuels Marketing Company

   Cramer

ExxonMobil Gas & Power Marketing Company

  

Swiger

ExxonMobil Lubricants & Petroleum Specialties Company

   Kohlenberger

ExxonMobil Production Company

   Foster and Swiger

ExxonMobil Refining & Supply Company

   Dolan, Hubble and Pryor

ExxonMobil Saudi Arabia

   Dolan

Imperial Oil Limited

   Mulva

 

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.

 

22


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Index to Financial Statements

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” portion of the Financial Section of this report.

 

Issuer Purchases of Equity Securities for Quarter Ended December 31, 2006  

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, 2006

   40,782,542    68.67    40,782,542       

November, 2006

   37,276,243    73.33    37,276,243       

December, 2006

   36,773,679    76.59    36,773,679       
    
       
      

Total

   114,832,464    72.72    114,832,464    (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.

 

23


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Index to Financial Statements

Item 6.    Selected Financial Data.

 

   

Years Ended December 31,


    2006

  2005

  2004

    2003  

    2002  

   

(millions of dollars, except per share amounts)

Sales and other operating revenue(1)(2)

  $ 365,467   $ 358,955   $ 291,252   $ 237,054   $ 200,949

(1) Sales-based taxes included.

  $ 30,381   $ 30,742   $ 27,263   $ 23,855   $ 22,040

(2) Includes amounts for purchases/sales contracts with the same counterparty for 2002-2005.

Net income

                             

Income from continuing operations

  $ 39,500   $ 36,130   $ 25,330   $ 20,960   $ 11,011

Discontinued operations, net of income tax

                    449

Cumulative effect of accounting change, net of income tax

                550    
   

 

 

 

 

Net income

  $ 39,500   $ 36,130   $ 25,330   $ 21,510   $ 11,460

Net income per common share

                             

Income from continuing operations

  $ 6.68   $ 5.76   $ 3.91   $ 3.16   $ 1.62

Discontinued operations, net of income tax

                    0.07

Cumulative effect of accounting change, net of income tax

                0.08    
   

 

 

 

 

Net income

  $ 6.68   $ 5.76   $ 3.91   $ 3.24   $ 1.69

Net income per common share - assuming dilution

                             

Income from continuing operations

  $ 6.62   $ 5.71   $ 3.89   $ 3.15   $ 1.61

Discontinued operations, net of income tax

                    0.07

Cumulative effect of accounting change, net of income tax

                0.08    
   

 

 

 

 

Net income

  $ 6.62   $ 5.71   $ 3.89   $ 3.23   $ 1.68
Cash dividends per common share   $ 1.28   $ 1.14   $ 1.06   $ 0.98   $ 0.92
Total assets   $ 219,015   $ 208,335   $ 195,256   $ 174,278   $ 152,644
Long-term debt   $ 6,645   $ 6,220   $ 5,013   $ 4,756   $ 6,655

 

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” in 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”, excluding the part entitled “Inflation and Other Uncertainties,” in 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.

 

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, 2007, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 18: Income, Sales-Based and Other Taxes;”

   

“Quarterly Information” (unaudited);

 

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Index to Financial Statements
   

“Supplemental Information on Oil and Gas Exploration and Production Activities” (unaudited); and

   

“Frequently Used Terms” (unaudited).

 

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, 2006. 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 accumulated and communicated 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, 2006.

 

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included in 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.

 

25


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Index to Financial Statements

PART III

 

Item 10.    Directors, Executive Officers and Corporate Governance.

 

Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2007 annual meeting of shareholders (the “2007 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”; and

   

The “Audit Committee” portion and the membership table of the portion entitled “Board Meetings and Committees; Annual Meeting Attendance” of the section entitled “Corporate Governance”.

 

Item 11.    Executive Compensation.

 

Incorporated by reference to the sections entitled “Director Compensation,” “Compensation Committee Report,” “Compensation Discussion and Analysis” and “Executive Compensation Tables” of the registrant’s 2007 Proxy Statement.

 

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

 

The information required under Item 403 of Regulation S-K is incorporated by reference to the section entitled “Director and Executive Officer Stock Ownership” of the registrant’s 2007 Proxy Statement.

 

Equity Compensation Plan Information

     (a)   (b)   (c)

Plan Category


  

Number of Securities to be

Issued Upon Exercise of

Outstanding Options,

Warrants and Rights


 

Weighted-
Average

Exercise Price of

Outstanding
Options,

Warrants and
Rights (1)


 

Number of Securities

Remaining Available for

Future Issuance Under

Equity Compensation
Plans

[Excluding Securities

Reflected in Column (a)]


Equity compensation plans approved by security holders

   104,121,419 (2)(3)   $40.18(3)   180,608,026(3)(4)(5)

Equity compensation plans not approved by security holders

  

0        

  0  

0        

Total

  

104,121,419      

 

$40.18  

 

180,608,026        

 

(1)   The exercise price of each option reflected in this table is equal to the fair market value of the Company’s common stock on the date the option was granted. The weighted-average price reflects six prior option grants that are still outstanding.

 

(2)   Includes 97,034,844 options granted under the 1993 Incentive Program and 7,086,575 restricted stock units to be settled in shares.

 

(3)   Does not include options that ExxonMobil assumed in the 1999 merger with Mobil. At year-end 2006, the number of securities to be issued upon exercise of outstanding options under Mobil plans was 13,452,414, and the weighted-average exercise price of such options was $29.36. No additional awards may be made under those plans.

 

(4)   Available shares can be granted in the form of restricted stock, options, or other stock-based awards. Includes 179,704,826 shares available for award under the 2003 Incentive Program and 903,200 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan.

 

26


Table of Contents
Index to Financial Statements
(5)   Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related standing resolution adopted by the Board, each non-employee director automatically receives 8,000 shares of restricted stock when first elected to the Board and, if the director remains in office, an additional 4,000 restricted shares each following year. While on the Board, each non-employee director receives the same cash dividends on restricted shares as a holder of regular common stock, but the director is not allowed to sell the shares. The restricted shares can be forfeited if the director leaves the Board early.

 

Item 13.    Certain Relationships and Related Transactions, and Director Independence.

 

The registrant has concluded that it has no disclosable matters under Item 404(a) of Regulation S-K. Additional information required under this Item 13 is incorporated by reference to the portions entitled “Related Person Transactions and Procedures” and “Director Independence” of the section entitled “Corporate Governance” in the registrant’s 2007 Proxy Statement.

 

Item 14.    Principal Accounting Fees and Services.

 

Incorporated by reference to the section entitled “Ratification of Independent Auditors” and the portion entitled “Audit Committee” of the section entitled “Corporate Governance” of the registrant’s 2007 Proxy Statement.

 

PART IV

 

Item 15.    Exhibits, Financial Statement Schedules.

 

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

See Table of Contents of the Financial Section of this report.

 

  (a) (3) Exhibits:

See Index to Exhibits of this report.

 

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Index to Financial Statements

 

 

[THIS PAGE INTENTIONALLY LEFT BLANK]

 

 

28


Table of Contents
Index to Financial Statements

FINANCIAL SECTION

 

TABLE OF CONTENTS     

Business Profile

   30

Financial Summary

   31

Frequently Used Terms

   32

Quarterly Information

   34

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

    

Functional Earnings

   35

Forward-Looking Statements

   36

Overview

   36

Business Environment and Risk Assessment

   36

Review of 2006 and 2005 Results

   37

Liquidity and Capital Resources

   39

Capital and Exploration Expenditures

   43

Taxes

   43

Environmental Matters

   44

Market Risks, Inflation and Other Uncertainties

   44

Recently Issued Statements of Financial Accounting Standards

   45

Critical Accounting Policies

   46

Management’s Report on Internal Control Over Financial Reporting

   50

Report of Independent Registered Public Accounting Firm

   50

Consolidated Financial Statements

    

Statement of Income

   52

Balance Sheet

   53

Statement of Shareholders’ Equity

   54

Statement of Cash Flows

   55

Notes to Consolidated Financial Statements

    

1. Summary of Accounting Policies

   56

2. Accounting Changes for Defined Benefit Pension and Other Postretirement Plans

   58

3. Miscellaneous Financial Information

   58

4. Cash Flow Information

   59

5. Additional Working Capital Information

   59

6. Equity Company Information

   60

7. Investments and Advances

   61

8. Property, Plant and Equipment and Asset Retirement Obligations

   61

9. Accounting for Suspended Exploratory Well Costs

   62

10. Leased Facilities

   65

11. Earnings Per Share

   65

12. Financial Instruments and Derivatives

   66

13. Long-Term Debt

   66

14. Incentive Program

   71

15. Litigation and Other Contingencies

   73

16. Pension and Other Postretirement Benefits

   75

17. Disclosures about Segments and Related Information

   79

18. Income, Sales-Based and Other Taxes

   81

Supplemental Information on Oil and Gas Exploration and Production Activities

   83

Operating Summary

   93

 

29


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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


   2006

   2005

    2006

   2005

   2006

   2005

   2006

   2005

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

Upstream

                                                    

United States

   $ 5,168    $ 6,200     $ 13,940    $ 13,491    37.1    46.0    $ 2,486    $ 2,142

Non-U.S.

     21,062      18,149       43,931      39,770    47.9    45.6      13,745      12,328
    

  


 

  

            

  

Total

   $ 26,230    $ 24,349     $ 57,871    $ 53,261    45.3    45.7    $ 16,231    $ 14,470
    

  


 

  

            

  

Downstream

                                                    

United States

   $ 4,250    $ 3,911     $ 6,456    $ 6,650    65.8    58.8    $ 824    $ 753

Non-U.S.

     4,204      4,081       17,172      18,030    24.5    22.6      1,905      1,742
    

  


 

  

            

  

Total

   $ 8,454    $ 7,992     $ 23,628    $ 24,680    35.8    32.4    $ 2,729    $ 2,495
    

  


 

  

            

  

Chemical

                                                    

United States

   $ 1,360    $ 1,186     $ 4,911    $ 5,145    27.7    23.1    $ 280    $ 243

Non-U.S.

     3,022      2,757       8,272      8,919    36.5    30.9      476      411
    

  


 

  

            

  

Total

   $ 4,382    $ 3,943     $ 13,183    $ 14,064    33.2    28.0    $ 756    $ 654
    

  


 

  

            

  

Corporate and financing

     434      (154 )     27,891      24,956    —      —        139      80
    

  


 

  

            

  

Total

   $ 39,500    $ 36,130     $ 122,573    $ 116,961    32.2    31.3    $ 19,855    $ 17,699
    

  


 

  

            

  

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

 

Operating


   2006

   2005

     (thousands of barrels daily)

Net liquids production

         

United States

   414    477

Non-U.S.

   2,267    2,046
    
  

Total

   2,681    2,523
    
  
     (millions of cubic feet daily)

Natural gas production available for sale

         

United States

   1,625    1,739

Non-U.S.

   7,709    7,512
    
  

Total

   9,334    9,251
    
  
     (thousands of oil-equivalent barrels daily)

Oil-equivalent production (1)

   4,237    4,065
     (thousands of barrels daily)
Petroleum product sales (2)          

United States

   2,729    2,822

Non-U.S.

   4,518    4,697
    
  

Total

   7,247    7,519
    
  
     (thousands of barrels daily)
Refinery throughput          

United States

   1,760    1,794

Non-U.S.

   3,843    3,929
    
  

Total

   5,603    5,723
    
  
     (thousands of metric tons)
Chemical prime product sales          

United States

   10,703    10,369

Non-U.S.

   16,647    16,408
    
  

Total

   27,350    26,777
    
  

(1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(2) Petroleum product sales data is reported net of purchases/sales contracts with the same counterparty.

 

30


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Index to Financial Statements

FINANCIAL SUMMARY

 

     2006

    2005

    2004

    2003

    2002

 
     (millions of dollars, except per share amounts)  

Sales and other operating revenue (1) (2)

   $ 365,467     $ 358,955     $ 291,252     $ 237,054     $ 200,949  

Earnings

                                        

Upstream

   $ 26,230     $ 24,349     $ 16,675     $ 14,502     $ 9,598  

Downstream

     8,454       7,992       5,706       3,516       1,300  

Chemical

     4,382       3,943       3,428       1,432       830  

Corporate and financing

     434       (154 )     (479 )     1,510       (442 )

Merger-related expenses

     —         —         —         —         (275 )
    


 


 


 


 


Income from continuing operations

   $ 39,500     $ 36,130     $ 25,330     $ 20,960     $ 11,011  

Discontinued operations

     —         —         —         —         449  

Accounting change

     —         —         —         550       —    
    


 


 


 


 


Net income

   $ 39,500     $ 36,130     $ 25,330     $ 21,510     $ 11,460  
    


 


 


 


 


Net income per common share

                                        

Income from continuing operations

   $ 6.68     $ 5.76     $ 3.91     $ 3.16     $ 1.62  

Net income per common share – assuming dilution

                                        

Income from continuing operations

   $ 6.62     $ 5.71     $ 3.89     $ 3.15     $ 1.61  

Discontinued operations, net of income tax

     —         —         —         —         0.07  

Cumulative effect of accounting change, net of income tax

     —         —         —         0.08       —    
    


 


 


 


 


Net income

   $ 6.62     $ 5.71     $ 3.89     $ 3.23     $ 1.68  
    


 


 


 


 


Cash dividends per common share

   $ 1.28     $ 1.14     $ 1.06     $ 0.98     $ 0.92  

Net income to average shareholders’ equity (percent)

     35.1       33.9       26.4       26.2       15.5  

Working capital

   $ 26,960     $ 27,035     $ 17,396     $ 7,574     $ 5,116  

Ratio of current assets to current liabilities

     1.55       1.58       1.40       1.20       1.15  

Additions to property, plant and equipment

   $ 15,462     $ 13,839     $ 11,986     $ 12,859     $ 11,437  

Property, plant and equipment, less allowances

   $ 113,687     $ 107,010     $ 108,639     $ 104,965     $ 94,940  

Total assets

   $ 219,015     $ 208,335     $ 195,256     $ 174,278     $ 152,644  

Exploration expenses, including dry holes

   $ 1,181     $ 964     $ 1,098     $ 1,010     $ 920  

Research and development costs

   $ 733     $ 712     $ 649     $ 618     $ 631  

Long-term debt

   $ 6,645     $ 6,220     $ 5,013     $ 4,756     $ 6,655  

Total debt

   $ 8,347     $ 7,991     $ 8,293     $ 9,545     $ 10,748  

Fixed-charge coverage ratio (times)

     46.3       50.2       36.1       30.8       13.8  

Debt to capital (percent)

     6.6       6.5       7.3       9.3       12.2  

Net debt to capital (percent) (3)

     (20.4 )     (22.0 )     (10.7 )     (1.2 )     4.4  

Shareholders’ equity at year end

   $ 113,844     $ 111,186     $ 101,756     $ 89,915     $ 74,597  

Shareholders’ equity per common share

   $ 19.87     $ 18.13     $ 15.90     $ 13.69     $ 11.13  

Weighted average number of common shares outstanding (millions)

     5,913       6,266       6,482       6,634       6,753  

Number of regular employees at year end (thousands) (4)

     82.1       83.7       85.9       88.3       92.5  

CORS employees not included above (thousands) (5)

     24.3       22.4       19.3       17.4       16.8  

(1) Sales and other operating revenue includes sales-based taxes of $30,381 million for 2006, $30,742 million for 2005, $27,263 million for 2004, $23,855 million for 2003 and $22,040 million for 2002.
(2) Sales and other operating revenue includes $30,810 million for 2005, $25,289 million for 2004, $20,936 million for 2003 and $18,150 million for 2002 for purchases/sales contracts with the same counterparty. Associated costs were included in Crude oil and product purchases. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net income. See note 1, Summary of Accounting Policies.
(3) Debt net of cash, excluding restricted cash. The ratio of net debt to capital including restricted cash is (26.3) percent for 2006.
(4) 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.
(5) CORS employees are employees of company-operated retail sites.

 

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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


   2006

   2005

   2004

     (millions of dollars)

Net cash provided by operating activities

   $ 49,286    $ 48,138    $ 40,551

Sales of subsidiaries, investments and property, plant and equipment

     3,080      6,036      2,754
    

  

  

Cash flow from operations and asset sales

   $ 52,366    $ 54,174    $ 43,305
    

  

  

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


   2006

    2005

    2004

 
     (millions of dollars)  

Business uses: asset and liability perspective

                        

Total assets

   $ 219,015     $ 208,335     $ 195,256  

Less liabilities and minority share of assets and liabilities

                        

Total current liabilities excluding notes and loans payable

     (47,115 )     (44,536 )     (39,701 )

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

     (45,905 )     (41,095 )     (41,554 )

Minority share of assets and liabilities

     (4,948 )     (4,863 )     (5,285 )

Add ExxonMobil share of debt-financed equity company net assets

     2,808       3,450       3,914  
    


 


 


Total capital employed

   $ 123,855     $ 121,291     $ 112,630  
    


 


 


Total corporate sources: debt and equity perspective

                        

Notes and loans payable

   $ 1,702     $ 1,771     $ 3,280  

Long-term debt

     6,645       6,220       5,013  

Shareholders’ equity

     113,844       111,186       101,756  

Less minority share of total debt

     (1,144 )     (1,336 )     (1,333 )

Add ExxonMobil share of equity company debt

     2,808       3,450       3,914  
    


 


 


Total capital employed

   $ 123,855     $ 121,291     $ 112,630  
    


 


 


 

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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 to make investment decisions.

 

Return on average capital employed


   2006

    2005

    2004

 
     (millions of dollars)  

Net income

   $ 39,500     $ 36,130     $ 25,330  

Financing costs (after tax)

                        

Third-party debt

     44       (1 )     (137 )

ExxonMobil share of equity companies

     (156 )     (144 )     (185 )

All other financing costs – net

     191       (295 )     54  
    


 


 


Total financing costs

     79       (440 )     (268 )
    


 


 


Earnings excluding financing costs

   $ 39,421     $ 36,570     $ 25,598  
    


 


 


Average capital employed

   $ 122,573     $ 116,961     $ 107,339  

Return on average capital employed – corporate total

     32.2 %     31.3 %     23.8 %

 

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Index to Financial Statements

QUARTERLY INFORMATION

 

     2006

   2005

     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

     2,698    2,702    2,647    2,678    2,681      2,544    2,468    2,451    2,629    2,523

Refinery throughput

     5,548    5,407    5,756    5,698    5,603      5,749    5,727    5,764    5,652    5,723

Petroleum product sales (1)

     7,177    7,060    7,302    7,447    7,247      7,494    7,510    7,477    7,592    7,519
     (millions of cubic feet daily)

Natural gas production available for sale

     11,175    8,754    8,139    9,301    9,334      10,785    8,709    7,716    9,822    9,251
     (thousands of oil-equivalent barrels daily)

Oil-equivalent production (2)

     4,560    4,161    4,004    4,228    4,237      4,341    3,919    3,737    4,266    4,065
     (thousands of metric tons)

Chemical prime product sales

     6,916    6,855    6,752    6,827    27,350      6,938    6,592    6,955    6,292    26,777

Summarized financial data

                                                     
     (millions of dollars)

Sales and other operating revenue (3) (4)

   $ 86,317    96,024    96,268    86,858    365,467    $ 79,475    86,622    96,731    96,127    358,955

Gross profit (5)

   $ 33,428    37,668    37,117    33,764    141,977    $ 31,525    32,962    35,336    36,841    136,664

Net income

   $ 8,400    10,360    10,490    10,250    39,500    $ 7,860    7,640    9,920    10,710    36,130
Per share data                                                      
     (dollars per share)

Net income per common share

   $ 1.38    1.74    1.79    1.77    6.68    $ 1.23    1.21    1.60    1.72    5.76

Net income per common share – assuming dilution

   $ 1.37    1.72    1.77    1.76    6.62    $ 1.22    1.20    1.58    1.71    5.71

Dividends per common share

   $ 0.32    0.32    0.32    0.32    1.28    $ 0.27    0.29    0.29    0.29    1.14

Common stock prices

                                                     

High

   $ 63.96    65.00    71.22    79.00    79.00    $ 64.37    61.74    65.96    63.89    65.96

Low

   $ 56.42    56.64    61.63    64.84    56.42    $ 49.25    52.78    57.60    54.50    49.25

(1) Petroleum product sales data is reported net of purchases/sales contracts with the same counterparty.
(2) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(3) 2005 Sales and other operating revenue includes amounts for purchases/sales with the same counterparty. Associated costs were included in Crude oil and product purchases. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net income. See note 1, Summary of Accounting Policies.
(4) Includes amounts for sales-based taxes.
(5) 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 591,226 registered shareholders of ExxonMobil common stock at December 31, 2006. At January 31, 2007, the registered shareholders of ExxonMobil common stock numbered 589,553.

On January 31, 2007, the Corporation declared a $0.32 dividend per common share, payable March 9, 2007.

 

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

 

FUNCTIONAL EARNINGS


   2006

   2005

    2004

 
     (millions of dollars, except per share amounts)  
Net income (U.S. GAAP)                        

Upstream

                       

United States

   $ 5,168    $ 6,200     $ 4,948  

Non-U.S.

     21,062      18,149       11,727  

Downstream

                       

United States

     4,250      3,911       2,186  

Non-U.S.

     4,204      4,081       3,520  

Chemical

                       

United States

     1,360      1,186       1,020  

Non-U.S.

     3,022      2,757       2,408  

Corporate and financing

     434      (154 )     (479 )
    

  


 


Net income

   $ 39,500    $ 36,130     $ 25,330  
    

  


 


Net income per common share

   $ 6.68    $ 5.76     $ 3.91  

Net income per common share – assuming dilution

   $ 6.62    $ 5.71     $ 3.89  

Special items included in net income

                       

Non-U.S. Upstream

                       

Gain on Dutch gas restructuring

   $ —      $ 1,620     $ —    

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

                       

Tax-related benefit

   $ 410    $ —       $ —    

 

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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 energy source 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 2006 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, manufacturing 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 88 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 are volatile on a short-term basis and depend 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 capital productivity.

BUSINESS ENVIRONMENT AND RISK ASSESSMENT

Long-Term Business Outlook

By 2030, the world’s population is expected to 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 60 percent by 2030 versus 2000. 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 will probably result from expected improvements in personal transportation and power generation driven by the introduction of new technologies, as well as many other improvements that span the residential, commercial and industrial sectors. Oil, gas and coal are expected to remain the predominant energy sources with approximately 80 percent share of total energy. Oil and gas are expected to maintain close to a 60 percent share. 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 average annual growth, solar and wind are expected to represent just 1 percent of the total energy portfolio by 2030.

Demand for liquid fuels is expected to grow at 1.4 percent per year, primarily due to increasing transportation requirements, especially related to light- and heavy-duty vehicles. The global fleet of light-duty vehicles will increase significantly, with related demand partly offset by improvements in fuel economy. Natural gas and coal are expected to grow at 1.7 and 1.6 percent per year, respectively, driven by increased need for electric power generation. The Corporation expects the liquefied natural gas (LNG) market to increase nearly fourfold by 2030, with LNG imports helping to meet growing demand 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 technological advances in gas liquefaction, transportation and regasification that enable distant gas supplies to reach markets economically.

The Corporation expects the world’s oil and gas resource 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 resources will be significant. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide through 2030 will be about $300 billion per year, or $8 trillion (measured in 2005 dollars) in total for 2005-2030.

Upstream

ExxonMobil continues to maintain a large portfolio of development and exploration opportunities, which enables the Corporation to be selective, optimizing total profitability and mitigating overall political and technical risks. As future development projects bring new production online, the Corporation expects a shift in the geographic mix of its production volumes between now and 2011. Oil and natural gas output from West Africa, the Caspian, the Middle East and Russia is expected to increase over the next five years based on current capital project execution plans. Currently, these growth areas account for 35 percent of the Corporation’s production. By 2011, 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. Nonconventional production utilizing specialized technology such as arctic technology, deepwater drilling and production systems, heavy oil recovery processes and LNG is expected to grow from about 30 to 40 percent of the Corporation’s output between now and 2011. The Corporation’s overall volume capacity outlook, based on projects coming onstream as anticipated, is for production capacity to grow over the period 2007-2011. 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, weather events, price effects under production sharing contracts and other factors described in Item 1A of ExxonMobil’s 2006 Form 10-K.

Downstream

The downstream industry environment remains very competitive. While refining margins in 2006 were strong, our long-term real inflation-adjusted 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 average-size refinery every three 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.

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 40 refineries, located in 20 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 around the world, serving a globally diverse customer base. World-class scale and integration, industry-leading efficiency, leading-edge technology and respected brands enable ExxonMobil to take advantage of attractive emerging-growth opportunities around the globe.

Chemical

The strength of the global economy supported strong demand growth for petrochemicals in 2006. Strong economic and industrial production growth fueled increased demand in Asia Pacific, particularly China. North America recovered from the supply disruptions created by hurricanes Katrina and Rita, while European growth was moderate, similar to that of GDP. Overall global supply/demand balances tightened, supporting higher prices and margins despite higher feedstock costs.

ExxonMobil benefited from continued operational excellence, 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, ExxonMobil 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, advantaged feedstock capabilities, leading proprietary technology and product application expertise.

REVIEW OF 2006 AND 2005 RESULTS

 

     2006

   2005

   2004

     (millions of dollars)

Net income (U.S. GAAP)

   $  39,500    $ 36,130    $  25,330

2006

Net income in 2006 of $39,500 million was the highest ever for the Corporation, up $3,370 million from 2005. Net income for 2006 included a $410 million gain from the recognition of tax benefits related to historical investments in non-U.S. assets.

Total assets at December 31, 2006, of $219 billion increased by approximately $11 billion from 2005, reflecting strong earnings and the Corporation’s active investment program, particularly in the Upstream.

2005

Net income in 2005 of $36,130 million was 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. Net income in 2004 included a special charge of $550 million relating to Allapattah.

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.

 

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

Upstream

 

     2006

   2005

   2004

     (millions of dollars)

Upstream

                    

United States

   $ 5,168    $ 6,200    $ 4,948

Non-U.S.

     21,062      18,149      11,727
    

  

  

Total

   $ 26,230    $ 24,349    $ 16,675
    

  

  

2006

Upstream earnings for 2006 totaled $26,230 million, an increase of $1,881 million from 2005, including a $1,620 million gain related to the Dutch gas restructuring in 2005. Higher liquids and natural gas realizations were partly offset by higher operating expenses. Oil-equivalent production increased 4 percent versus 2005, including the impact of divestment and entitlement effects. Excluding these impacts, total oil-equivalent production increased by 7 percent. Liquids production of 2,681 kbd (thousands of barrels per day) increased by 158 kbd from 2005. Production increases from new projects in West Africa and increased Abu Dhabi volumes were partly offset by mature field decline, entitlement effects and divestment impacts. Natural gas production of 9,334 mcfd (millions of cubic feet per day) increased 83 mcfd from 2005. Higher volumes from projects in Qatar were partly offset by mature field decline. Earnings from U.S. Upstream operations for 2006 were $5,168 million, a decrease of $1,032 million. Earnings outside the U.S. for 2006 were $21,062 million, an increase of $2,913 million, including a $1,620 million gain related to the Dutch gas restructuring in 2005.

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 volumes. 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 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 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.

Downstream

 

     2006

   2005

   2004

     (millions of dollars)

Downstream

                    

United States

   $ 4,250    $ 3,911    $ 2,186

Non-U.S.

     4,204      4,081      3,520
    

  

  

Total

   $ 8,454    $ 7,992    $ 5,706
    

  

  

2006

Downstream earnings totaled $8,454 million, an increase of $462 million from 2005 including a $310 million gain for the 2005 Sinopec share sale and a special charge of $200 million related to the 2005 Allapattah lawsuit provision. Stronger worldwide refining and marketing margins were partly offset by lower refining throughput. Petroleum product sales of 7,247 kbd decreased from 7,519 kbd in 2005, primarily due to lower refining throughput and divestment impacts. Refinery throughput was 5,603 kbd compared with 5,723 kbd in 2005. U.S. Downstream earnings of $4,250 million increased by $339 million, including a 2005 special charge related to the Allapattah lawsuit provision. Non-U.S. Downstream earnings of $4,204 million were $123 million higher than 2005 earnings which included a gain for the Sinopec share sale.

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 (net) of 7,519 kbd increased from 7,511 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.

Chemical

 

     2006

   2005

   2004

     (millions of dollars)

Chemical

                    

United States

   $ 1,360    $ 1,186    $ 1,020

Non-U.S.

     3,022      2,757      2,408
    

  

  

Total

   $ 4,382    $ 3,943    $ 3,428
    

  

  

2006

Chemical earnings totaled $4,382 million, an increase of $439 million from 2005, including a $390 million gain from the favorable resolution of joint venture litigation in 2005 and a $150 million gain for the 2005 Sinopec share sale. Increased 2006 earnings were driven by higher margins and increased sales volumes. Prime product sales were 27,350 kt (thousands of metric tons), an increase of 573 kt. Prime product sales are total chemical product sales including ExxonMobil’s share of equity-company volumes and finished-product transfers to the Downstream business. Carbon black oil and sulfur volumes are excluded. U.S. Chemical earnings of $1,360 million increased by $174 million. Non-U.S. Chemical earnings of $3,022 million were $265 million

 

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Index to Financial Statements

higher than 2005 earnings, which included gains from the favorable resolution of joint venture litigation and the Sinopec share sale.

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, partly offset by higher worldwide margins. Prime product sales were 26,777 kt, a decrease of 1,011 kt from 2004, largely reflecting the impact of hurricanes Katrina and Rita. 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.

Corporate and Financing

 

     2006

   2005

    2004

 
     (millions of dollars)  

Corporate and financing

   $  434    $ (154 )   $ (479 )

2006

The corporate and financing segment contributed $434 million to earnings in 2006, up $588 million from 2005, primarily due to a $410 million gain from tax benefits related to historical investments in non-U.S. assets and higher interest income.

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.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

 

     2006

    2005

 
     (millions of dollars)  

Net cash provided by/(used in)

                

Operating activities

   $ 49,286     $ 48,138  

Investing activities

     (14,230 )     (10,270 )

Financing activities

     (36,210 )     (26,941 )

Effect of exchange rate changes

     727       (787 )
    


 


Increase/(decrease) in cash and cash equivalents

   $ (427 )   $ 10,140  
    


 


     (Dec. 31)  

Cash and cash equivalents

   $ 28,244     $ 28,671  

Cash and cash equivalents – restricted

     4,604       4,604  
    


 


Total cash and cash equivalents

   $ 32,848     $ 33,275  
    


 


Cash and cash equivalents were $28,244 million at the end of 2006, comparable to the prior year, as a net reduction from operating, investing and financing activities was partly offset by $727 million of positive foreign exchange effects from the general weakening of the U.S. dollar in 2006. Including restricted cash and cash equivalents of $4,604 million (see note 3 and note 15), total cash and cash equivalents were $32,848 million at the end of 2006. Cash and cash equivalents were $28,671 million at the end of 2005, an increase of $10,140 million from 2004, including $787 million of negative 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, total cash and cash equivalents were $33,275 million at the end of 2005. Cash flows from operating, investing and financing activities are discussed below. For additional details, see the Consolidated Statement of Cash Flows.

        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, 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 2006 were $19.9 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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Index to Financial Statements

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

Cash Flow from Operating Activities

2006

Cash provided by operating activities totaled $49.3 billion in 2006, a $1.1 billion increase from 2005. The major source of funds was net income of $39.5 billion, adjusted for the noncash provision of $11.4 billion for depreciation and depletion, both of which increased. The net timing effects of receipts of notes and accounts receivable, payments of accounts and other payables and contributions to pension funds in 2006 provided a partial offset.

2005

Cash provided by operating activities totaled $48.1 billion in 2005, a $7.6 billion increase from 2004. The major source of funds was net income of $36.1 billion, which increased $10.8 billion. The adjustment for the noncash provision for depreciation and depletion was $10.3 billion. Contributing to the increased level of cash provided by operating activities in 2005 was the net timing effects of receipts of notes and accounts receivable and payments of accounts and other payables in a rising price environment.

Cash Flow from Investing Activities

2006

Cash used in investing activities totaled $14.2 billion in 2006, $4.0 billion higher than 2005. Spending for property, plant and equipment increased $1.6 billion. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $3.1 billion in 2006 decreased $3.0 billion, reflecting a lower level of asset sales and the absence of almost $1.4 billion from the sale of the Corporation’s interest in Sinopec in 2005.

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. 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.

Cash Flow from Financing Activities

2006

Cash used in financing activities was $36.2 billion, an increase of $9.3 billion from 2005, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.28 per share from $1.14 per share and totaled $7.6 billion, a payout of 19 percent. Total consolidated short-term and long-term debt increased $0.3 billion to $8.3 billion at year-end 2006.

Shareholders’ equity increased $2.7 billion in 2006, to $113.8 billion, reflecting $39.5 billion of net income reduced by distributions to ExxonMobil shareholders of $7.6 billion of dividends and $25.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding. Shareholders’ equity, and net assets and liabilities, increased $2.8 billion, representing the foreign exchange translation effects of stronger foreign currencies at the end of 2006 on ExxonMobil’s operations outside the United States. Recognition of the “Postretirement benefits reserves adjustment” under Financial Accounting Standard No. 158 (see note 2) reduced shareholders’ equity by $6.5 billion.

During 2006, Exxon Mobil Corporation purchased 451 million shares of its common stock for the treasury at a gross cost of $29.6 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 6.6 percent from 6,133 million at the end of 2005 to 5,729 million at the end of 2006. 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.

2005

Cash used in financing activities was $26.9 billion, an increase of $8.7 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, 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 United States.

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 reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 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.

 

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Index to Financial Statements

Commitments

Set forth below is information about the outstanding commitments of the Corporation’s consolidated subsidiaries at December 31, 2006. It combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.

 

     Payments Due by Period

Commitments


   Note
Reference
Number


   2007

   2008-
2011


  

2012

and
Beyond


   Total

     (millions of dollars)

Long-term debt (1)

   13    $ —      $ 684    $ 5,961    $ 6,645

– Due in one year (2)

          459      —        —        459

Asset retirement obligations (3)

   8      266      1,167      3,270      4,703

Pension and other postretirement obligations (4)

   16      1,318      3,144      10,002      14,464

Operating leases (5)

   10      2,252      4,361      2,090      8,703

Unconditional purchase obligations (6)

   15      587      1,797      1,599      3,983

Take-or-pay obligations (7)

          780      2,474      2,036      5,290

Firm capital commitments (8)

          5,024      2,823      1,186      9,033

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 $220 million.
(2) The amount due in one year is included in notes and loans payable of $1,702 million (note 5).
(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 the benefit obligations exceeded the fair value of fund assets for certain U.S. and non-U.S. pension and other postretirement plans at year end. The payments by period include expected contributions to funded pension plans in 2007 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 $3,983 million mainly pertain to pipeline throughput agreements and include $2,039 million of obligations to equity companies. The present value of the total commitments, excluding imputed interest of $1,127 million, was $2,856 million.
(7) Take-or-pay obligations are noncancelable, long-term commitments for goods and services other than UPOs. The undiscounted obligations of $5,290 million mainly pertain to pipeline and terminaling agreements and include $1,847 million of obligations to equity companies. The present value of the total commitments, excluding imputed interest of $1,118 million, totaled $4,172 million.
(8) Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $9.0 billion. These commitments were predominantly associated with Upstream projects outside the U.S., of which $3.2 billion was associated with LNG projects in Qatar and natural gas projects in Malaysia. The Corporation expects to fund the majority of these projects through internal cash flow.

Guarantees

The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2006, for $4,252 million, primarily relating to guarantees for notes, loans and performance under contracts (note 15). Included in this amount were guarantees by consolidated affiliates of $3,507 million, representing ExxonMobil’s share of obligations of certain equity companies. The below-mentioned guarantees are not reasonably likely to have a material 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, 2006

     Equity
Company
Obligations


   Other
Third-Party
Obligations


   Total

     (millions of dollars)

Total guarantees

   $  3,507    $ 745    $ 4,252

 

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Index to Financial Statements

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

Financial Strength

On December 31, 2006, unused credit lines for short-term financing totaled approximately $5.8 billion (note 5).

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 88 years.

 

     2006

  2005

  2004

Fixed-charge coverage ratio (times)

   46.3   50.2   36.1

Debt to capital (percent)

   6.6   6.5   7.3

Net debt to capital (percent) (1)

   (20.4)   (22.0)   (10.7)

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 (26.3) percent for 2006.

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 note 12.

Litigation and Other Contingencies

As discussed in note 15, 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. All 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. The Corporation posted a $5.4 billion letter of credit. ExxonMobil and the plaintiffs appealed this decision to the Ninth Circuit, which ruled on December 22, 2006, that the award be reduced to $2.5 billion. On January 12, 2007, ExxonMobil petitioned the Ninth Circuit Court of Appeals for a rehearing en banc of its appeal. While it is reasonably possible that a liability for punitive damages 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. The Alabama Supreme Court heard oral arguments on February 6, 2007. 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 which, in March 2006, refused to hear the appeal. ExxonMobil has fully accrued and paid the compensatory and punitive damage awards. The Corporation appealed the punitive damage award to the U.S. Supreme Court, which on February 26, 2007, vacated the judgment and remanded the case to the Louisiana Fourth Circuit Court of Appeals for reconsideration in light of the recent U.S. Supreme Court decision in Williams v. Phillip Morris USA.

 

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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 a 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. The District Court has given final approval of a settlement of $1,075 million, pre-tax. This obligation has been fully accrued and was paid in the second quarter 2006.

Tax issues for 1989 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

 

     2006

   2005

     U.S.

   Non-U.S.

   U.S.

   Non-U.S.

     (millions of dollars)

Upstream (1)

   $ 2,486    $ 13,745    $ 2,142    $ 12,328

Downstream

     824      1,905      753      1,742

Chemical

     280      476      243      411

Other

     130      9      80      —  
    

  

  

  

Total

   $ 3,720    $ 16,135    $ 3,218    $ 14,481
    

  

  

  

 

(1) Exploration expenses included.

Capital and exploration expenditures in 2006 were $19.9 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 the progress of individual projects.

Upstream spending was up 12 percent to $16.2 billion in 2006, from $14.5 billion in 2005, as a result of higher spending in growth areas such as Qatar, Abu Dhabi and West Africa. In addition, spending in the United States and the North Sea was also higher. During the past three years, Upstream capital and exploration expenditures averaged $14.1 billion. The majority of these expenditures are on 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 $2.7 billion in 2006, up $0.2 billion from 2005. Chemical capital expenditures were up $0.1 billion from 2005.

TAXES

 

     2006

    2005

    2004

 
     (millions of dollars)  

Income taxes

   $ 27,902     $ 23,302     $ 15,911  

Sales-based taxes

     30,381       30,742       27,263  

All other taxes and duties

     42,393       44,571       43,605  
    


 


 


Total

   $ 100,676     $ 98,615     $ 86,779  
    


 


 


Effective income tax rate

     43 %     41 %     40 %

2006

Income, sales-based and all other taxes and duties totaled $100.7 billion in 2006, an increase of $2.1 billion or 2 percent from 2005. Income tax expense, both current and deferred, was $27.9 billion, $4.6 billion higher than 2005, reflecting higher pre-tax income in 2006. The effective tax rate was 43 percent in 2006, compared to 41 percent in 2005. During both periods, the Corporation continued to benefit from the favorable resolution of tax-related issues. Sales-based and all other taxes and duties of $72.8 billion in 2006 decreased $2.5 billion from 2005, reflecting the tax impact of net reporting of purchases and sales of inventory with the same counterparty, only partly offset by the effects of higher prices.

2005

Income, sales-based and all other taxes and duties 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 percent in 2005, compared to 40 percent in 2004. During both periods, the Corporation continued to benefit from the favorable resolution of tax-related issues. Sales-based 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.

 

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

ENVIRONMENTAL MATTERS

Environmental Expenditures

 

     2006

   2005

     (millions of dollars)

Capital expenditures

   $ 1,081    $ 1,240

Other expenditures

     2,127      2,089
    

  

Total

   $ 3,208    $ 3,329
    

  

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels as well as projects to reduce nitrogen oxide and sulfur oxide emissions and expenditures for asset retirement obligations. ExxonMobil’s 2006 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $3.2 billion. The total cost for such activities is expected to remain in this range in 2007 and 2008 (with capital expenditures approximately 40 percent of the total).

Environmental Liabilities

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 could mitigate 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. Consolidated company provisions made in 2006 for environmental liabilities were $350 million ($487 million in 2005) and the balance sheet reflects accumulated liabilities of $864 million as of December 31, 2006, and $849 million as of December 31, 2005.

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 ($263 million for 2006). Over time, the liabilities are accreted for the increase in their present value, with this effect included in expenses ($243 million in 2006). Consolidated company expenditures for asset retirement obligations in 2006 were $238 million and the ending balance of the obligations recorded on the balance sheet at December 31, 2006, totaled $4,703 million.

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

 

Worldwide Average Realizations (1)


   2006

   2005

   2004

Crude oil and NGL ($/barrel)

   $ 58.34    $ 48.23    $ 34.76

Natural gas ($/kcf)

     6.08      5.96      4.48

 

(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 2006 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 at market-based prices. 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 over a broad range of future prices. 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 12 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 2006 and 2005.

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 generally been countered by cost reductions from efficiency and productivity improvements. Increased global demand for certain services and materials has resulted in higher operating and capital costs in recent years. The Corporation continues to mitigate these effects through its economies of scale in global procurement and its efficient project management practices.

RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS

Accounting for Uncertainty in Income Taxes

In June 2006 the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes.” FIN 48 is an interpretation of FASB Statement No. 109, “Accounting for Income Taxes,” and must be adopted by the Corporation no later than January 1, 2007. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that the company has taken or expects to take in its returns. The Corporation expects to recognize a transition gain of approximately $0.3 billion in shareholders’ equity upon adoption of FIN 48 in the first quarter of 2007. This gain reflects the recognition of several refund claims, partly offset by increased liability reserves.

 

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

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, the Corporation does not use specific quantitative reserve targets to determine compensation.

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.

Beginning in 2004, the year-end reserves volumes as well as the reserves change categories shown in the proved reserves tables are calculated using December 31 prices and costs. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. Regulations preclude the Corporation from showing in this document the reserves that are calculated in a manner that is consistent with the basis that the Corporation uses to make its investment decisions. 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, (2) new geologic, reservoir or production data or (3) changes in year-end prices and costs that are 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. The Corporation uses this accounting policy instead of the “full cost” method because it provides a more timely accounting of the success or failure of the Corporation’s exploration and production activities. If the full cost method were used, all costs would be capitalized and depreciated on a country-by-country basis. The capitalized costs would be subject to an impairment test by country. The full cost method would tend to delay the expense recognition of unsuccessful projects.

 

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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 actual volumes produced to total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods), applied to the 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. While the 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 and gas 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 significantly, 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 price assumptions developed in the annual planning and budgeting process for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are 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 is provided following the notes to the financial statements. The standardized measure of discounted future cash flows is based on the year-end 2006 price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (FAS 69), “Disclosure about Oil and Gas Producing Activities.” 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 2006 are disclosed in note 9 to the financial statements.

 

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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 share of the undivided interest in certain 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 non-consolidated 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.

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.

Pension 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. The Pension and Other Postretirement Benefits note 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 United States, 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. 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 2006 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 $120 million before tax.

 

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Differences between actual returns on fund assets versus the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees. Further details on pension accounting and related disclosures can be found in notes 2 and 16.

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. Management has regular litigation and tax reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in note 15.

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. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss.

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 use the local currency, except in highly inflationary countries (primarily in Latin America) and 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. Operations using 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, 2006.

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, 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 consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, 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 consolidated financial statements listed under Item 8 of the Form 10-K present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, 2006, and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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 2 to the consolidated financial statements, the Corporation changed its method of accounting for defined benefit pension and other postretirement plans in 2006.

 

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Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Corporation maintained effective internal control over financial reporting as of December 31, 2006, 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, 2006, 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, 2007

 

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CONSOLIDATED STATEMENT OF INCOME

 

     Note
Reference
Number


   2006

   2005

   2004

          (millions of dollars)

Revenues and other income

                         

Sales and other operating revenue (1) (2)

        $ 365,467    $ 358,955    $ 291,252

Income from equity affiliates

   6      6,985      7,583      4,961

Other income

          5,183      4,142      1,822
         

  

  

Total revenues and other income

        $ 377,635    $ 370,680    $ 298,035
         

  

  

Costs and other deductions

                         

Crude oil and product purchases

        $ 182,546    $ 185,219    $ 139,224

Production and manufacturing expenses

          29,528      26,819      23,225

Selling, general and administrative expenses

          14,273      14,402      13,849

Depreciation and depletion

          11,416      10,253      9,767

Exploration expenses, including dry holes

          1,181      964      1,098

Interest expense

          654      496      638

Sales-based taxes (1)

   18      30,381      30,742      27,263

Other taxes and duties

   18      39,203      41,554      40,954

Income applicable to minority and preferred interests

          1,051      799      776
         

  

  

Total costs and other deductions

        $ 310,233    $ 311,248    $ 256,794
         

  

  

Income before income taxes

        $ 67,402    $ 59,432    $ 41,241

Income taxes

   18      27,902      23,302      15,911
         

  

  

Net income

        $ 39,500    $ 36,130    $ 25,330
         

  

  

Net income per common share (dollars)

   11    $ 6.68    $ 5.76    $ 3.91

Net income per common share – assuming dilution (dollars)

   11    $ 6.62    $ 5.71    $ 3.89

 

(1) Sales and other operating revenue includes sales-based taxes of $30,381 million for 2006, $30,742 million for 2005 and $27,263 million for 2004.
(2) Sales and other operating revenue includes $30,810 million for 2005 and $25,289 million for 2004 for purchases/sales contracts with the same counterparty. Associated costs were included in Crude oil and product purchases. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net income. See note 1, Summary of Accounting Policies.

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

 

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CONSOLIDATED BALANCE SHEET

 

     Note
Reference
Number


   Dec. 31
2006


    Dec. 31
2005


 
          (millions of dollars)  

Assets

                     

Current assets

                     

Cash and cash equivalents

        $ 28,244     $ 28,671  

Cash and cash equivalents – restricted

   3, 15      4,604       4,604  

Notes and accounts receivable, less estimated doubtful amounts

   5      28,942       27,484  

Inventories

                     

Crude oil, products and merchandise

   3      8,979       7,852  

Materials and supplies

          1,735       1,469  

Prepaid taxes and expenses

          3,273       3,262  
         


 


Total current assets

        $ 75,777     $ 73,342  

Investments and advances

   7      23,237       20,592  

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

   8      113,687       107,010  

Other assets, including intangibles, net

          6,314       7,391  
         


 


Total assets

        $ 219,015     $ 208,335  
         


 


Liabilities

                     

Current liabilities

                     

Notes and loans payable

   5    $ 1,702     $ 1,771  

Accounts payable and accrued liabilities

   5      39,082       36,120  

Income taxes payable

          8,033       8,416  
         


 


Total current liabilities

        $ 48,817     $ 46,307  

Long-term debt

   13      6,645       6,220  

Postretirement benefits reserves

   16      13,931       10,220  

Accrued liabilities

          7,116       6,434  

Deferred income tax liabilities

   18      20,851       20,878  

Deferred credits and other long-term obligations

          4,007       3,563  

Equity of minority and preferred shareholders in affiliated companies

          3,804       3,527  
         


 


Total liabilities

        $ 105,171     $ 97,149  
         


 


Commitments and contingencies

   15                 

Shareholders’ equity

                     

Common stock without par value
(9,000 million shares authorized, 8,019 million shares issued)

        $ 4,786     $ 4,477  

Earnings reinvested

          195,207       163,335  

Accumulated other nonowner changes in equity

                     

Cumulative foreign exchange translation adjustment

          3,733       979  

Postretirement benefits reserves adjustment

          (6,495 )     —    

Minimum pension liability adjustment

          —         (2,258 )

Common stock held in treasury (2,290 million shares in 2006 and 1,886 million shares in 2005)

          (83,387 )     (55,347 )
         


 


Total shareholders’ equity

        $ 113,844     $ 111,186  
         


 


Total liabilities and shareholders’ equity

        $ 219,015     $ 208,335  
         


 


The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

 

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CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

 

          2006

   2005

    2004

 
     Note
Reference
Number


   Shareholders’
Equity


    Nonowner
Changes in
Equity
(1)


   Shareholders’
Equity


    Nonowner
Changes in
Equity


    Shareholders’
Equity


    Nonowner
Changes in
Equity


 
          (millions of dollars)  

Common stock

                                                    

At beginning of year

        $ 4,477            $ 4,053             $ 3,834          

Restricted stock amortization

          480              356               173          

Tax benefits related to stock-based awards

          169              224               183          

Other

          (340 )            (156 )             (137 )        
         


        


         


       

At end of year

        $ 4,786            $ 4,477             $ 4,053          
         


        


         


       

Earnings reinvested

                                                    

At beginning of year

          163,335              134,390               115,956          

Net income for the year

          39,500     $ 39,500      36,130     $ 36,130       25,330     $ 25,330  

Dividends – common shares

          (7,628 )            (7,185 )             (6,896 )        
         


        


         


       

At end of year

        $ 195,207            $ 163,335             $ 134,390          
         


        


         


       

Accumulated other nonowner changes in equity

                                                    

At beginning of year

          (1,279 )            1,527               (514 )        

Foreign exchange translation adjustment

          2,754       2,754      (2,619 )     (2,619 )     2,177       2,177  

Postretirement benefits reserves adjustment

   16      (6,495 )     —        —         —         —         —    

Minimum pension liability adjustment

   16      2,258       749      241       241       (53 )     (53 )

Unrealized gains/(losses) on stock investments

          —         —        —         —         (83 )     (83 )

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

          —         —        (428 )     (428 )     —         —    
         


        


         


       

At end of year

        $ (2,762 )          $ (1,279 )           $ 1,527          
         


 

  


 


 


 


Total

                $ 43,003            $ 33,324             $ 27,371  
                 

          


         


Common stock held in treasury

                                                    

At beginning of year

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

Acquisitions, at cost

          (29,558 )            (18,221 )             (9,951 )        

Dispositions

          1,518              1,088               1,098          
         


        


         


       

At end of year

        $ (83,387 )          $ (55,347 )           $ (38,214 )        
         


        


         


       

Shareholders’ equity at end of year

        $ 113,844            $ 111,186             $ 101,756          
         


        


         


       
     Share Activity

 
          2006

         2005

          2004

       
     (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

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

Acquisitions

          (451 )            (311 )             (218 )        

Dispositions

          47              43               51          
         


        


         


       

At end of year

          (2,290 )            (1,886 )             (1,618 )        
         


        


         


       

Common shares outstanding at end of year

          5,729              6,133               6,401          
         


        


         


       

 

(1) Includes pre-FAS 158 adoption change in minimum pension liability.

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

 

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Index to Financial Statements

CONSOLIDATED STATEMENT OF CASH FLOWS

 

     Note
Reference
Number


   2006

    2005

    2004

 
          (millions of dollars)  

Cash flows from operating activities

                             

Net income

                             

Accruing to ExxonMobil shareholders

        $ 39,500     $ 36,130     $ 25,330  

Accruing to minority and preferred interests

          1,051       799       776  

Adjustments for noncash transactions

                             

Depreciation and depletion

          11,416       10,253       9,767  

Deferred income tax charges/(credits)

          1,717       (429 )     (1,134 )

Postretirement benefits expense in excess of/(less than) payments

          (1,787 )     254       886  

Accrued liability provisions in excess of/(less than) payments

          (666 )     398       806  

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

          (579 )     (734 )     (1,643 )

Changes in operational working capital, excluding cash and debt

                             

Reduction/(increase) – Notes and accounts receivable

          (181 )     (3,700 )     (472 )

                                                       – Inventories

          (1,057 )     (434 )     (223 )

                                                       – Prepaid taxes and expenses

          (385 )     (7 )     11  

Increase/(reduction) – Accounts and other payables

          1,160       7,806       6,333  

Net (gain) on asset sales

   4      (1,531 )     (1,980 )     (268 )

All other items – net

          628       (218 )     382  
         


 


 


Net cash provided by operating activities

        $ 49,286     $ 48,138     $ 40,551  
         


 


 


Cash flows from investing activities

                             

Additions to property, plant and equipment

        $ (15,462 )   $ (13,839 )   $ (11,986 )

Sales of subsidiaries, investments and property, plant and equipment

   4      3,080       6,036       2,754  

Increase in restricted cash and cash equivalents

   3, 15      —         —         (4,604 )

Additional investments and advances

          (2,604 )     (2,810 )     (2,287 )

Collection of advances

          756       343       1,213  
         


 


 


Net cash used in investing activities

        $ (14,230 )   $ (10,270 )   $ (14,910 )
         


 


 


Cash flows from financing activities

                             

Additions to long-term debt

        $ 318     $ 195     $ 470  

Reductions in long-term debt

          (33 )     (81 )     (562 )

Additions to short-term debt

          334       377       450  

Reductions in short-term debt

          (451 )     (687 )     (2,243 )

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

          (95 )     (1,306 )     (66 )

Cash dividends to ExxonMobil shareholders

          (7,628 )     (7,185 )     (6,896 )

Cash dividends to minority interests

          (239 )     (293 )     (215 )

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

          (493 )     (681 )     (215 )

Tax benefits related to stock-based awards

          462       —         —    

Common stock acquired

          (29,558 )     (18,221 )     (9,951 )

Common stock sold

          1,173       941       960  
         


 


 


Net cash used in financing activities

        $ (36,210 )   $ (26,941 )   $ (18,268 )
         


 


 


Effects of exchange rate changes on cash

        $ 727     $ (787 )   $ 532  
         


 


 


Increase/(decrease) in cash and cash equivalents

        $ (427 )   $ 10,140     $ 7,905  

Cash and cash equivalents at beginning of year

          28,671       18,531       10,626  
         


 


 


Cash and cash equivalents at end of year

        $ 28,244     $ 28,671     $ 18,531  
         


 


 


The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

 

55


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Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation.

The Corporation’s principal business is energy, involving the worldwide exploration, production, transportation and sale of crude oil and natural gas (Upstream) and the manufacture, transportation and sale of petroleum products (Downstream). The Corporation is also a major worldwide manufacturer and marketer of petrochemicals (Chemical) and participates in electric power generation (Upstream).

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain cases to conform to the 2006 presentation basis.

1. Summary of Accounting Policies

Principles of Consolidation. The Consolidated Financial Statements include the accounts of those significant subsidiaries owned directly or indirectly with more than 50 percent of the voting rights held by the Corporation and for which other shareholders do not possess the right to participate in significant management decisions. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities. Additionally, 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.

Amounts representing the Corporation’s percentage interest in the underlying net assets of other significant subsidiaries and less-than-majority-owned companies in which a significant ownership percentage interest is held 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 Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in the Consolidated Statement of Shareholders’ Equity. Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed to determine if such evidence represents a loss in value of the Corporation’s investment that is other than temporary. Examples of key indicators include a history of operating losses, a negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.

Revenue Recognition. The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments. In all cases, revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured.

Revenues from the production of natural gas properties in which the Corporation has an interest with other producers are recognized on the basis of the Corporation’s net working interest. Differences between actual production and net working interest volumes are not significant.

Effective January 1, 2006, the Corporation adopted the Emerging Issues Task Force (EITF) consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” 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. In prior periods, the Corporation recorded certain crude oil, natural gas, petroleum product and chemical sales and purchases contemporaneously negotiated with the same counterparty as revenues and purchases. As a result of the EITF consensus, the Corporation’s accounts “Sales and other operating revenue,” “Crude oil and product purchases” and “Other taxes and duties” on the Consolidated Statement of Income were reduced in 2006 by associated amounts with no impact on net income. All operating segments are affected by this change, with the largest impact in the Downstream.

Sales-Based Taxes. The Corporation reports sales, excise and value-added taxes on sales transactions on a gross basis in the Consolidated Statement of Income (included in both revenues and costs). This gross reporting basis is footnoted on the Consolidated Statement of Income.

Derivative Instruments. The Corporation makes limited use of derivative instruments. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and transactions.

The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates derivatives as fair value hedges, in which case the gains and losses are offset in income by the gains and losses arising from changes in the fair value of the underlying hedged items.

 

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Inventories. Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.

Property, Plant and Equipment. Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.

Interest costs incurred to finance expenditures during the construction phase of multiyear projects are capitalized as part of the historical cost of acquiring the constructed assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Capitalized interest costs are included in property, plant and equipment and are depreciated over the service life of the related assets.

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.

The Corpora