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

2008


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, 2008

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 (4,941,630,490 shares
outstanding at January 31, 2009)

   New York Stock Exchange
Registered securities guaranteed by Registrant:     

SeaRiver Maritime Financial Holdings, Inc.

    

Twenty-Five Year Debt Securities due October 1, 2011

   New York Stock Exchange

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes   ü    No        

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ü   

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer    ü           Accelerated filer                 

Non-accelerated filer                  Smaller reporting company        

 

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, 2008, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $88.13 on the New York Stock Exchange composite tape, was in excess of $457 billion.

 

Documents Incorporated by Reference:

    Proxy Statement for the 2009 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, 2008

 

TABLE OF CONTENTS

 

     Page
Number


PART I
Item 1.   

Business

   1
Item 1A.   

Risk Factors

   2
Item 1B.   

Unresolved Staff Comments

   6
Item 2.   

Properties

   6
Item 3.   

Legal Proceedings

   26
Item 4.   

Submission of Matters to a Vote of Security Holders

   27
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]    28
PART II
Item 5.   

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

   29
Item 6.   

Selected Financial Data

   30
Item 7.   

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

   30
Item 7A.   

Quantitative and Qualitative Disclosures About Market Risk

   30
Item 8.   

Financial Statements and Supplementary Data

   30
Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure    31
Item 9A.    Controls and Procedures    31
Item 9B.    Other Information    31
PART III
Item 10.   

Directors, Executive Officers and Corporate Governance

   31
Item 11.   

Executive Compensation

   32
Item 12.   

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

   32
Item 13.   

Certain Relationships and Related Transactions, and Director Independence

   33
Item 14.   

Principal Accounting Fees and Services

   33
PART IV
Item 15.   

Exhibits, Financial Statement Schedules

   33
Signatures    98
Index to Exhibits    100
Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges     
Exhibits 31 and 32 — Certifications     


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Index to Financial Statements

PART I

 

Item 1.    Business.

 

Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. 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 2008 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $5.2 billion, of which $2.5 billion were capital expenditures and $2.7 billion were included in expenses. The total cost for such activities is expected to remain in this range in 2009 and 2010 (with capital expenditures approximately 50 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. ExxonMobil has a long-standing commitment to the development of proprietary technology. We have a wide array of research programs designed to meet the needs identified in each of our business segments. Information on Company-sponsored research and development spending is contained in “Note 3: Miscellaneous Financial Information” of the Financial Section of this report. ExxonMobil held approximately 11 thousand active patents worldwide at the end of 2008. For technology licensed to third parties, revenues totaled approximately $125 million in 2008. Although technology is an important contributor to the overall operations and results of our Company, the profitability of each business segment is not dependent on any individual patent, trade secret, trademark, license, franchise or concession.

 

The number of regular employees was 79.9 thousand, 80.8 thousand and 82.1 thousand at years ended 2008, 2007 and 2006, 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 24.8 thousand, 26.3 thousand and 24.3 thousand at years ended 2008, 2007 and 2006, respectively.

 

ExxonMobil maintains a website at 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

 

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furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission. Also available on the Corporation’s website are the Company’s Corporate Governance Guidelines and Code of Ethics and Business Conduct, as well as the charters of the audit, compensation and nominating committees of the Board of Directors. All of these documents are available in print without charge to shareholders who request them. Information on our website is not incorporated into this report.

 

Item 1A.     Risk Factors.

 

ExxonMobil’s financial and operating results are subject to a variety of risks inherent in the global oil and gas business. Many of these risk factors are not within the Company’s control and could adversely affect our business, our financial and operating results or our financial condition. 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.

 

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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;

 

   

other political developments and laws and regulations, such as expropriation or forced divestiture of assets, unilateral cancellation or modification of contract terms, and 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.

 

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).

 

The Corporation’s overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity to grow over the period 2009-2013. 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 described above.

 

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Index to Financial Statements

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.

 

Market Risk Factors:    

 

Worldwide Average Realizations—Consolidated Subsidiaries


   2008

   2007

   2006

Crude oil and NGL ($/barrel)

   $ 89.32    $ 66.02    $ 58.34

Natural gas ($/kcf)

     7.54      5.29      6.08

 

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 a $1 per barrel change in the weighted-average realized price of oil would have approximately a $375 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 $175 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 broad indicators 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 & 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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Index to Financial Statements

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 investments 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.

 

The Corporation has an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the Corporation’s strategic objectives. The result is an efficient capital base, and the Corporation has seldom had 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: Financial Instruments and Derivatives” of the Financial Section of this report 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 on its short-term debt and the portion of long-term debt that carries 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 2008 and 2007. During 2008, credit markets tightened and the global economy slowed. The Corporation is not dependent on the credit markets to fund current operations. However, some joint-venture partners are dependent on the credit markets and their funding ability may impact the development pace of joint-venture projects.

 

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 many major countries of operation increased in 2008 versus the relatively low rates in recent years, and the associated impact on non-energy costs has generally been mitigated by cost reductions from efficiency and productivity improvements. Increased global

 

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demand for certain services and materials has resulted in higher operating and capital costs in recent years. The Corporation works to counter upward pressure on costs through its economies of scale in global procurement and its efficient project management practices.

 

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

 

Item 1B.     Unresolved Staff Comments.

 

None.

 

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 2008

 

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, 2008, 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, 2008. The Corporation has reported 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.

 

     Liquids

   Natural Gas

   Oil-Equivalent
Basis


     (millions of barrels)    (billions of cubic feet)    (millions of barrels)

United States

   1,644    11,778    3,607

Canada/South America

   812    1,383    1,042

Europe

   533    5,445    1,441

Africa

   2,137    918    2,290

Asia Pacific/Middle East

   1,737    11,137    3,593

Russia/Caspian

   713    741    837
    
  
  

Total consolidated

   7,576    31,402    12,810
    
  
  

 

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

 

     Year-End 2008

   Year-End 2007

     Developed

   Undeveloped

   Developed

   Undeveloped

     (millions of oil-equivalent barrels)

Consolidated Subsidiaries

                   

United States

   2,563    1,044    2,723    1,323

Canada/South America

   771    271    899    300

Europe

   1,148    293    1,362    396

Africa

   1,407    883    1,331    895

Asia Pacific/Middle East

   2,197    1,396    2,055    1,061

Russia/Caspian

   166    671    157    677
    
  
  
  

Total

   8,252    4,558    8,527    4,652
    
  
  
  

Equity Companies

                   

United States

   280    66    316    79

Europe

   1,556    444    1,621    462

Asia Pacific/Middle East

   2,766    2,070    2,121    2,929

Russia/Caspian

   754    369    637    413
    
  
  
  

Total

   5,356    2,949    4,695    3,883
    
  
  
  

 

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 2009-2013. 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 2008, 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 2007, 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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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 2007 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. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

 

4.    Gross and Net Productive Wells

 

     Year-End 2008

   Year-End 2007

     Oil

   Gas

   Oil

   Gas

     Gross

   Net

   Gross

   Net

   Gross

   Net

   Gross

   Net

United States

   27,247    10,186    9,092    5,515    27,444    10,320    9,112    5,516

Canada/South America

   5,527    5,007    6,189    3,189    5,714    5,092    6,211    3,240

Europe

   1,345    391    1,217    478    1,599    477    1,188    472

Africa

   943    381    14    6    853    350    16    6

Asia Pacific/Middle East

   2,182    564    313    199    2,195    573    272    183

Russia/Caspian

   142    29          119    24      
    
  
  
  
  
  
  
  

Total

   37,386    16,558    16,825    9,387    37,924    16,836    16,799    9,417
    
  
  
  
  
  
  
  

 

There were 16,286 gross and 13,573 net operated wells at year-end 2008 and 16,797 gross and 13,945 net operated wells at year-end 2007.

 

5.    Gross and Net Developed Acreage

 

     Year-End 2008

   Year-End 2007

     Gross

   Net

   Gross

   Net

     (thousands of acres)

United States

   8,746    5,148    9,001    5,174

Canada/South America

   5,444    2,459    5,391    2,337

Europe

   10,172    4,026    10,730    4,194

Africa

   1,958    756    1,889    729

Asia Pacific/Middle East

   8,161    1,651    8,124    1,649

Russia/Caspian

   531    116    531    116
    
  
  
  

Total

   35,012    14,156    35,666    14,199
    
  
  
  

 

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 2008

   Year-End 2007

     Gross

   Net

   Gross

   Net

     (thousands of acres)

United States

   9,064    5,691    9,104    5,539

Canada/South America

   32,700    19,741    32,399    22,353

Europe

   16,875    7,913    13,552    6,002

Africa

   40,440    26,439    39,935    24,835

Asia Pacific/Middle East

   18,699    12,190    20,904    13,167

Russia/Caspian

   1,952    372    1,952    392
    
  
  
  

Total

   119,730    72,346    117,846    72,288
    
  
  
  

 

        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

 

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. Under certain circumstances, a lease may be held beyond its exploration term even if production has not commenced. In some instances, a “fee interest” is acquired where both the surface and the underlying mineral interests are owned outright.

 

CANADA / SOUTH AMERICA

 

Canada

 

Exploration permits are granted for varying periods of time with renewals possible. Exploration rights in onshore areas acquired from Canadian provinces entitle the holder to obtain leases upon completing specified work. 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 and the block in the Beaufort Sea acquired in 2007 are currently held by work commitments of various amounts.

 

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.

 

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EUROPE

 

Germany

 

Exploration concessions are granted for an initial maximum period of five years, with an unlimited number of extensions of up to three years each. 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. In May 2007, ExxonMobil affiliates acquired four exploration licenses over 1.3 million acres in the Lower Saxony Basin. The exploration licenses are for a period of five years during which exploration work programs will be carried out.

 

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.

 

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.

 

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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. In May 2007, Chad enacted a new Petroleum Code which would govern new acquisitions.

 

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 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. In 2000, a Memorandum of Understanding (MOU) was executed defining commercial terms applicable to existing joint venture oil production. The MOU may be terminated on one calendar year’s notice.

 

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.

 

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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. 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 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 seven production sharing contracts (PSCs) negotiated with the national oil company, three governing exploration and production activities and four governing production activities only. The more recent PSCs governing exploration and production activities 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.

 

In 2008, the Company reached agreement with the national oil company for a new PSC. Under the new PSC, from 2008 until March 31, 2012, the Company is entitled to undertake new development and production activities of areas, in oil fields under an existing PSC, subject to new minimum work and spending commitments. When the existing PSC expires on March 31, 2012, the producing fields covered by the existing PSC, as well as those areas developed by the Company under the new PSC, all automatically become part of the new PSC, which has a 25-year duration from April 2008.

 

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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. Recent amendments of the Oil and Gas Act provide that extensions of Petroleum Retention licenses may be for periods of less than one year, renewable annually, if the Minister considers at the time of extension that the resources could become commercially viable in less than five years.

 

Qatar

 

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

 

Republic of Yemen

 

Existing production operations under the production sharing agreements (PSAs) 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 concession holders brought an action for arbitration over the Government’s actions, but the arbitration panel in 2008 ruled in favor of the Government.

 

Thailand

 

The Petroleum Act of 1971 allows production under ExxonMobil’s concession for 30 years with a 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.

 

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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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8.    Number of Net Productive and Dry Wells Drilled

 

    2008

   2007

   2006

A. Net Productive Exploratory Wells Drilled

             

United States

  10    12    10

Canada/South America

     1    3

Europe

  4    2    2

Africa

  3    2    4

Asia Pacific/Middle East

  2    1    2

Russia/Caspian

     1   
   
  
  

Total

  19    19    21
   
  
  

B. Net Dry Exploratory Wells Drilled

             

United States

  3    8    5

Canada/South America

     1    1

Europe

  2    2    2

Africa

  2    4    4

Asia Pacific/Middle East

  2    1   

Russia/Caspian

       
   
  
  

Total

  9    16    12
   
  
  

C. Net Productive Development Wells Drilled

             

United States

  426    451    552

Canada/South America

  223    377    373

Europe

  10    16    22

Africa

  39    43    64

Asia Pacific/Middle East

  28    26    25

Russia/Caspian

  5    4    5
   
  
  

Total

  731    917    1,041
   
  
  

D. Net Dry Development Wells Drilled

             

United States

  3    15    5

Canada/South America

  1       1

Europe

     3    4

Africa

     1    1

Asia Pacific/Middle East

       

Russia/Caspian

       
   
  
  

Total

  4    19    11
   
  
  

Total number of net wells drilled

  763    971    1,085
   
  
  

 

9.    Present Activities

 

A. Wells Drilling

 

     Year-End 2008

   Year-End 2007

     Gross

   Net

   Gross

   Net

United States

   203    137    118    65

Canada/South America

   297    173    187    125

Europe

   28    7    41    6

Africa

   19    7    30    11

Asia Pacific/Middle East

   22    11    46    25

Russia/Caspian

   25    4    36    5
    
  
  
  

Total

   594    339    458    237
    
  
  
  

 

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B. Review of Principal Ongoing Activities

 

During 2008, 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.

 

UNITED STATES

 

ExxonMobil’s year-end 2008 acreage holdings totaled 10.8 million net acres, of which 2.3 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

 

During 2008, 416.4 net exploration and development wells were completed in the inland lower 48 states and 2.0 net development wells were completed offshore in the Pacific. Tight gas development continued in the Piceance Basin of Colorado. Participation in Alaska production and development continued and a total of 20.5 net development wells were drilled. On Alaska’s North Slope, activity continued on the Western Region Development (primarily the Orion field) with development drilling and engineering design for future facility expansions.

 

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2008 was 2.1 million acres. A total of 3.5 net exploration and development wells were completed during the year. Activity on the Thunder Horse project continued, with production from the deepwater semi-submersible development commencing in 2008. Work to rebuild and reinstall subsea equipment resulting from subsea manifold failures continued.

 

Construction of the Golden Pass LNG regasification terminal in Texas continued in 2008. The terminal will have the capacity to deliver up to two billion cubic feet of gas per day.

 

CANADA / SOUTH AMERICA

 

Canada

 

ExxonMobil’s year-end 2008 acreage holdings totaled 8.0 million net acres, of which 3.9 million net acres were offshore. A total of 221.2 net development wells were completed during the year.

 

Argentina

 

ExxonMobil’s net acreage totaled 0.2 million onshore acres at year-end 2008, and there were 3.3 net development wells completed during the year.

 

Venezuela

 

ExxonMobil’s acreage holdings and assets were expropriated in 2007. Refer to the relevant portion of “Note 15: Litigation and Other Contingencies” of the Financial Section of this report for additional information.

 

EUROPE

 

Germany

 

A total of 3.1 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2008, with 3.5 net development and exploration wells drilled during the year.

 

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Italy

 

Construction of the Adriatic LNG regasification terminal continued in 2008. The terminal was moved from its construction site to its final location offshore Italy for commissioning. The terminal will have the capacity to supply up to 775 million cubic feet of gas per day to the Italian gas market.

 

Netherlands

 

ExxonMobil’s net interest in licenses totaled approximately 1.5 million acres at year-end 2008, of which 1.2 million acres were onshore. A total of 2.7 net exploration and development wells were completed during the year. Offshore, construction of the L09 project was completed. Onshore, the project to redevelop the previously abandoned Schoonebeek oil field commenced. In addition, the multi-year project to renovate Groningen production clusters, install new compression to maintain capacity, and extend field life continued.

 

Norway

 

ExxonMobil’s net interest in licenses at year-end 2008 totaled approximately 0.8 million acres, all offshore. ExxonMobil participated in 8.3 net exploration and development well completions in 2008. Production was initiated at Volve and construction on the Tyrihans project continued.

 

United Kingdom

 

ExxonMobil’s net interest in licenses at year-end 2008 totaled approximately 1.4 million acres, all offshore. A total of 1.2 net exploration and development wells were completed during the year. The Starling and Caravel projects started up in 2008, while the St. Fergus gas processing facilities refurbishment project continued to make progress.

 

Construction of the South Hook LNG regasification terminal in Wales continued in 2008. The terminal will have the capacity to deliver up to two billion cubic feet of gas per day into the natural gas grid.

 

AFRICA

 

Angola

 

ExxonMobil’s year-end 2008 acreage holdings totaled 0.7 million net offshore acres and 10.5 net exploration and development wells were completed during the year. On Block 15, development drilling continued at Kizomba A and Kizomba B. The Block’s fourth major development, Kizomba C, began production from the Mondo and Saxi/Batuque fields in 2008. A block-wide 3D and 4D seismic acquisition program concluded during the year. On the non-operated Block 17, project work continued on the Pazflor project in 2008 and development drilling continued at Rosa and Dalia. The Plutao-Saturno-Venus-Marte (PSVM) project on Block 31 (non-operated) was approved in 2008.

 

Cameroon

 

ExxonMobil’s net acreage holdings totaled 0.1 million offshore acres.

 

Chad

 

ExxonMobil’s net year-end 2008 acreage holdings consisted of 3.3 million onshore acres, with 22.8 net development wells completed during the year. Work began on the Timbre field, with production expected in 2009.

 

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Equatorial Guinea

 

ExxonMobil’s acreage totaled 0.2 million net offshore acres at year-end 2008.

 

Nigeria

 

ExxonMobil’s net acreage totaled 1.0 million offshore acres at year-end 2008, with 10.9 net exploration and development wells completed during the year. The ExxonMobil-operated East Area Natural Gas Liquids II project started up in 2008. This project reduced flared gas and will recover high-value natural gas liquids from the gas stream. Work continued on the deepwater Usan project in 2008. A 3D seismic acquisition program that will provide enhanced resolution of existing fields and target deeper formations progressed. Appraisal drilling continued at Bonga North, Erha North East and Bosi North Deep fields.

 

ASIA PACIFIC / MIDDLE EAST

 

Australia

 

ExxonMobil’s net year-end 2008 offshore acreage holdings totaled 2.4 million acres. During 2008, a total of 3.0 net development wells were drilled. Work continued on the Kipper gas project and the Turrum Phase 2 development project was approved in 2008.

 

Indonesia

 

At year-end 2008, ExxonMobil had 5.1 million net acres, 4.1 million acres offshore and 1.0 million acres onshore and 1.4 net exploration wells were completed during the year. Project activities continued on the Banyu Urip development in the Cepu Contract area.

 

Japan

 

ExxonMobil’s net offshore acreage was 36 thousand acres at year-end 2008.

 

Malaysia

 

ExxonMobil has interests in production sharing contracts covering 0.5 million net acres offshore Malaysia at year-end 2008. During the year, a total of 9.8 net development wells were completed. The Tapis F and Jerneh B gas platforms started up in 2008.

 

Papua New Guinea

 

A total of 0.4 million net onshore acres were held by ExxonMobil at year-end 2008, with 0.9 net exploration and development wells completed during the year.

 

Qatar

 

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

 

Qatar Liquefied Gas Company Limited — (QG I)

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

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

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

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

 

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In addition, ExxonMobil’s Al Khaleej Gas (AKG) Phase 1 project supplied pipeline gas to domestic industrial customers. The AKG facilities have sales gas capacity of up to 750 mcfd (millions of cubic feet per day) and produce 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 2008, 93 (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 2008, ExxonMobil had 0.1 million net offshore acres. During 2008, 10.3 net exploration and development wells were completed.

 

Qatar LNG capacity volumes (gross) at year-end 2008 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 2008 commissioning activities commenced at QG II train 4. 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, and 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.

 

Thailand

 

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2008.

 

United Arab Emirates

 

ExxonMobil’s net acreage in the Abu Dhabi oil concessions was 0.6 million acres at year-end 2008, of which 0.4 million acres were onshore and 0.2 million acres offshore. During the year, a total of 5.7 net exploration and development wells were completed. During 2008, work progressed on multiple field development projects, both onshore and offshore, to sustain and increase oil production capacity.

 

RUSSIA/CASPIAN

 

Azerbaijan

 

At year-end 2008, ExxonMobil’s net acreage, located in the Caspian Sea offshore of Azerbaijan, totaled 0.1 million acres. At the Azeri-Chirag-Gunashli field, 1.2 net development wells were completed and production ramp-up continued. The Phase 3 Deep Water Gunashli project started up in 2008.

 

Kazakhstan

 

ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2008, with 0.7 net development wells completed during 2008. The initial phase of the Tengiz expansion started up in 2007, followed by the full expansion in 2008. Construction of the initial phase of the Kashagan field continued during 2008.

 

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Russia

 

ExxonMobil’s net acreage holdings at year-end 2008 were 0.1 million acres, all offshore. A total of 2.7 net development wells were completed in the Chayvo field during the year. Phase 1 facilities include an offshore platform, onshore well site (from which extended reach horizontal drilling was completed in 2008), an onshore processing plant, an oil pipeline from Sakhalin Island to the Russian mainland, a mainland crude storage and loading terminal and an offshore loading buoy for loading shipments of oil by tanker.

 

WORLDWIDE EXPLORATION

 

At year-end 2008, exploration activities were underway in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 46 million net acres were held at year-end 2008. No 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, mines 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 1.9 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 250,000 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 (located on lease 17) was depleted and ceased production in 2007. 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 830,000 tons of oil sands per day, producing 150 million barrels of crude bitumen per 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

 

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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 2008, this upgrading process yielded 0.859 barrels of synthetic crude oil per barrel of crude bitumen. In 2008 about 39 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 61 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 $2.8 billion at year-end 2008.

 

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 180 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 are within the operating North and Aurora mines. In accordance with the approved mining plan, there are extractable oil sands in the North and Aurora mines, with average bitumen grades of 10.6 and 11.2 weight percent, respectively. 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 2008 was equivalent to 734 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 added a remote mining train and expanded 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.

 

On May 1, 2007, the company implemented a management services agreement under which Syncrude will be provided with operational, technical and business management services from Imperial Oil Limited and Exxon Mobil Corporation. The agreement has an initial term of 10 years and may be terminated with at least two years prior written notice.

 

In November 2008, Imperial Oil Limited, along with the other Syncrude joint-venture owners, signed an agreement with the Government of Alberta to amend the existing Syncrude Crown Agreement. Under the amended agreement, beginning January 1, 2010, Syncrude will begin transitioning to the new oil sands royalty regime by paying additional royalties, the exact amount of which will depend on production levels from 2010 to 2015. Also, beginning January 1, 2009, Syncrude’s royalty will be based on bitumen value with upgrading costs and revenues excluded from the calculation.

 

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ExxonMobil Net Proven Syncrude Reserves (1)

 

     Synthetic Crude Oil

 
     North Mine

    Aurora
Mine

    Total

 
     (millions of barrels)  

January 1, 2008

   188     506     694  

Revision of previous estimate

   27     36     63  

Production

   (11 )   (12 )   (23 )
    

 

 

December 31, 2008

   204     530     734  
    

 

 


(1)   Net reserves are the share of reserves based on an estimate of average royalty rates over the life of the project and incorporate amendments to the Syncrude Crown Agreement.

 

Syncrude Operating Statistics (total operation)

 

    2008

  2007

  2006

  2005

  2004

Operating Statistics

                   

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

  165.3   132.2   128.2   97.1   100.3

Mined overburden to oil sands ratio(1)

  1.35   1.06   1.18   1.02   0.94

Oil sands mined (millions of tons)

  216.4   221.0   195.5   168.0   188.0

Average bitumen grade (weight percent)

  11.1   11.6   11.4   11.1   11.1
   
 
 
 
 

Crude bitumen in mined oil sands (millions of tons)

  24.0   25.6   22.2   18.6   20.9

Average extraction recovery (percent)

  90.3   91.8   90.3   89.1   87.3
   
 
 
 
 

Crude bitumen production (millions of barrels)(2)

  122.5   132.5   111.6   94.2   103.3

Average upgrading yield (percent)

  85.9   84.3   84.9   85.3   85.5
   
 
 
 
 

Gross synthetic crude oil produced (millions of barrels)

  107.6   113.0   95.5   79.3   88.4

ExxonMobil net share (millions of barrels)(3)

  23   24   21   19   22

(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.

 

Kearl Project

 

Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. The Kearl project is located approximately 40 miles north of Fort McMurray, Alberta. The location is currently accessible by an existing road. Imperial Oil Limited holds a 70.96 percent participating interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest in ExxonMobil Canada Properties.

 

Kearl will be developed in three phases. Bitumen will be extracted from oil sands produced from open-pit mining operations, and processed through a bitumen extraction and froth treatment plant. The product, a heavy oil blend of bitumen and diluent, will be shipped via pipelines for distribution to North American markets. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation to market by pipeline.

 

Operating License and Leases

 

The Kearl project received approvals from the Province of Alberta in 2007 and the Government of Canada in 2008. The Province of Alberta issued an operating and construction license in 2008, which permits the project to mine oil sands and produce bitumen from approved development areas on oil sands leases. Kearl is comprised of six oil sands leases covering about 48,000 acres in the Athabasca oil

 

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Index to Financial Statements

sands deposit. The leases, which are issued by the Province of Alberta, are automatically renewable as long as the oil sands operations are ongoing or the leases are part of an approved development plan. The leases involved in the first phase of the project are 6, 87 and 88A (which contain proven reserves) and 31A, 36 and 88B (which do not currently contain proven reserves). There were no known previous commercial operations on these leases.

 

Operations, Plant and Equipment

 

Production from the first phase is expected to average approximately 110,000 barrels of bitumen a day, before royalties. About $500 million has been spent on the first phase. Activities in 2008 focused on engineering work to define the project design and execution plan. Other activities in 2008 also included site access road construction, site preparation and earthworks. Significant progress has also been made on transportation system agreements.

 

Kearl will be subject to the Alberta generic oil sands royalty regime, which was modified in 2007 and which will take effect in 2009. Royalty rates will be based upon a sliding scale, determined by the price of crude oil.

 

Operations at Kearl will involve three main processes: open-pit mining, extraction of crude bitumen and diluent blending. The open-pit mining will utilize truck, shovel and hydrotransport systems. The extraction separates crude bitumen from sand through a froth processing plant. Electricity will be provided initially through the Alberta grid. Recycled water will be the primary water source, and incremental raw water will be drawn, under license, from the Athabasca River.

 

Proven Reserves

 

Bitumen deposits at Kearl are found throughout sandstones within the Lower, Middle and Upper McMurray members, concentrated primarily within the Middle and Upper McMurray members. The oil sands occur over depths ranging from approximately 30 feet to as much as 450 feet below surface. The oil sands are about 130 feet in net thickness, but can be as thick as 230 feet. Mined bitumen reserve estimates are based upon detailed geological and engineering assessments of in-place crude bitumen volumes, the mining plan, demonstrated extraction recovery factors, planned operating capacity and operating approval limits. The in-place volume, depth and grade of the first phase were established through extensive and closely spaced core drilling with spacing of approximately 1,400 feet (14 wells per section). The determination of reserves uses a seven percent bitumen grade cut-off by weight, a 77 percent overall extraction recovery (paraffinic froth treatment process) and a 95 percent mining dilution factor.

 

ExxonMobil Net Proven Kearl Reserves (1)

 

     Total

     (millions of barrels)

January 1, 2008

  

Additions

   1,137

Production

  
    

December 31, 2008

   1,137
    

(1)   Net reserves are the share of reserves based on an estimate of average royalty rates over the life of the project and incorporate the Alberta oil sands royalty regime.

 

Information with regard to the Downstream segment follows:

 

ExxonMobil’s Downstream segment manufactures and sells petroleum products. The refining and supply operations encompass a global network of manufacturing plants, transportation systems, and distribution centers that provide a range of fuels, lubricants and other products and feedstocks to our customers around the world.

 

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Refining Capacity At Year-End 2008 (1)

 

          ExxonMobil
Share KBD (2)

   ExxonMobil
Interest %

United States

              

Torrance

  

California

   150    100

Joliet

  

Illinois

   240    100

Baton Rouge

  

Louisiana

   503    100

Baytown

  

Texas

   573    100

Beaumont

  

Texas

   345    100

Other (2 refineries)

   157     
         
    

Total United States

   1,968     

Canada

              

Strathcona

  

Alberta

   187    69.6

Dartmouth

  

Nova Scotia

   82    69.6

Nanticoke

  

Ontario

   112    69.6

Sarnia

  

Ontario

   121    69.6
         
    

Total Canada

   502     

Europe

              

Antwerp

  

Belgium

   305    100

Fos-sur-Mer

  

France

   119    82.9

Port-Jerome-Gravenchon

  

France

   233    82.9

Augusta

  

Italy

   198    100

Trecate

  

Italy

   174    75.4

Rotterdam

  

Netherlands

   191    100

Slagen

  

Norway

   116    100

Fawley

  

United Kingdom

   326    100

Other (2 refineries)

   78     
         
    

Total Europe

   1,740     

Asia Pacific

              

Kawasaki (3)

  

Japan

   296    50

Sakai (3)

  

Japan

   139    50

Wakayama (3)

  

Japan

   155    50

Jurong/PAC

  

Singapore

   605    100

Sriracha

  

Thailand

   174    66

Other (6 refineries)

   301     
         
    

Total Asia Pacific

   1,670     

Other Non-U.S.

              

Yanbu

  

Saudi Arabia

   200    50

Other (4 refineries)

   130     
         
    

Total Other Non-U.S.

   330     
         
    

Total Worldwide

   6,210     
         
    

(1)   Capacity data is based on 100 percent of rated refinery process unit stream-day capacities under normal operating conditions, less the impact of shutdowns for regular repair and maintenance activities, averaged over an extended period of time.

 

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Index to Financial Statements
(2)   Thousands of barrels per day (KBD). ExxonMobil share reflects 100 percent of atmospheric distillation capacity in operations of ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent or less, ExxonMobil share is the greater of ExxonMobil’s equity interest or that portion of distillation capacity normally available to ExxonMobil.
(3)   Operated by majority-owned subsidiaries.

 

The marketing operations sell products and services throughout the world. Our Exxon, Esso, Mobil and On the Run brands serve customers at nearly 29,000 retail service stations.

 

Retail Sites Year-End 2008

 

United States

    

Owned/leased

   2,155

Distributors/resellers

   8,296
    

Total United States

   10,451

Canada

    

Owned/leased

   557

Distributors/resellers

   1,314
    

Total Canada

   1,871

Europe

    

Owned/leased

   4,131

Distributors/resellers

   2,796
    

Total Europe

   6,927

Asia Pacific

    

Owned/leased

   2,416

Distributors/resellers

   4,253
    

Total Asia Pacific

   6,669

Latin America

    

Owned/leased

   776

Distributors/resellers

   1,372
    

Total Latin America

   2,148

Middle East/Africa

    

Owned/leased

   481

Distributors/resellers

   127
    

Total Middle East/Africa

   608

Worldwide

    

Owned/leased

   10,516

Distributors/resellers

   18,158
    

Total worldwide

   28,674
    

 

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Information with regard to the Chemical segment follows:

 

ExxonMobil’s Chemical segment manufactures and sells petrochemicals. The Chemical business supplies olefins, polyolefins, aromatics, and a wide variety of other petrochemicals.

 

Chemical Complex Capacity at Year-End 2008 (1) (2)

 

        Ethylene

  Polyethylene

  Polypropylene

  Paraxylene

  ExxonMobil
Interest %

 

North America

                         

Baton Rouge

 

Louisiana

  1.0   1.3   0.4     100  

Baytown

 

Texas

  2.2     0.8   0.6   100  

Beaumont

 

Texas

  0.9   1.0     0.3   100  

Mont Belvieu

 

Texas

    1.0       100  

Sarnia

 

Ontario

  0.3   0.5       69.6  
       
 
 
 
     

Total North America

  4.4   3.8   1.2   0.9      

Europe

                         

Antwerp

 

Belgium

  0.5   0.4       35 (3)

Fawley

 

United Kingdom

  0.1         100  

Fife

 

United Kingdom

  0.4         50  

Meerhout

 

Belgium

    0.5       100  

Notre-Dame-de-
Gravenchon

 

France

  0.4   0.4   0.4     100  

Rotterdam

 

Netherlands

        0.6   100  
       
 
 
 
     

Total Europe

  1.4   1.3   0.4   0.6      

Middle East

                         

Al Jubail

 

Saudi Arabia

  0.6   0.6       50  

Yanbu

 

Saudi Arabia

  1.0   0.7   0.2     50  
       
 
 
 
     

Total Middle East

  1.6   1.3   0.2        

Asia Pacific

                         

Kawasaki

 

Japan

  0.5   0.1       50  

Singapore

 

Singapore

  0.9   0.6   0.4   0.9   100  

Sriracha

 

Thailand

        0.5   66  
       
 
 
 
     

Total Asia Pacific

  1.4   0.7   0.4   1.4      

All Other

        0.6      
       
 
 
 
     

Total Worldwide

  8.8   7.1   2.2   3.5      
       
 
 
 
     

(1)   Capacity for ethylene, polyethylene, polypropylene and paraxylene in millions of metric tons.
(2)   Capacity reflects 100 percent for operations of ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent or less, capacity is ExxonMobil’s interest.
(3)   Net ExxonMobil ethylene capacity is 35%. Net ExxonMobil polyethylene capacity is 100%.

 

Item 3.    Legal Proceedings.

 

On November 21, 2008, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order and Notice of Potential Penalty to the Corporation’s refinery located in Baton Rouge, Louisiana. The Order requires the refinery to take corrective actions related to self-disclosed emissions exceedances involving the refinery’s wet gas scrubber and wastewater treatment. Although penalties have not yet been assessed, they are likely to exceed $100,000. The LDEQ has also issued interim permit limits for these sources until the required corrective action steps can be completed during an upcoming scheduled turnaround.

 

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Regarding a previously reported matter, the Corporation and Chalmette Refining, LLC have agreed to pay stipulated penalties demanded by the United States Environmental Protection Agency (EPA) for alleged noncompliance under their respective 2005 and 2006 consent decrees relating to EPA’s New Source Review Enforcement Initiative. The EPA issued its demand for stipulated penalties to Chalmette Refining, LLC ($273,500) on October 17, 2008, and to the Corporation ($6,064,500) on December 17, 2008. Most of the penalties are associated with alleged noncompliance with New Source Performance Standards Subpart J. Chalmette Refining, LLC paid its penalty in November, 2008, and the Corporation paid its penalty in February, 2009.

 

Regarding a previously reported matter, on December 23, 2008, the office of the United States Attorney for the District of Massachusetts filed a misdemeanor criminal information alleging that ExxonMobil Pipeline Company violated 33 U.S.C. Sections 1319(c)(1) and 1321(b)(3) of the Clean Water Act resulting from a spill that occurred on or about January 9-10, 2006, on the Island End River near the Corporation’s Everett Terminal facility in Everett, Massachusetts. A plea agreement intended to resolve the case was also filed with the Federal District Court on that same date. The plea agreement requires that ExxonMobil Pipeline Company plead guilty to a misdemeanor violation 33 U.S.C. Section 1319(c)(1) of the Clean Water Act and agree to the following: (1) a term of probation of three years; (2) fund and implement an environmental compliance plan for the three year probationary period; (3) pay a fine of $359,018 and a special assessment of $125 (4) pay $5,640,982 in community service payments to the North American Wetlands Conservation Act Fund; and (5) pay $179,509 for spill-related cleanup costs. A hearing was held by the court on January 22, 2009, to review the plea agreement. The court took the matter under consideration, with sentencing to occur in the future.

 

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.

 


 

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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,

2009


 

Title (Held Office Since)


R. W. Tillerson

 

56

 

Chairman of the Board (2006)

M. W. Albers

 

52

 

Senior Vice President (2007)

M. J. Dolan

 

55

 

Senior Vice President (2008)

D. D. Humphreys

 

61

 

Senior Vice President (2006) and Treasurer (2004)

A. T. Cejka

 

57

 

Vice President (2004)

W. M. Colton

 

55

 

Vice President - Strategic Planning (2009)

H. R. Cramer

 

58

 

Vice President (1999)

N. W. Duffin

 

52

 

President, ExxonMobil Development Company (2007)

S. J. Glass, Jr.

  61  

Vice President (2008)

A. J. Kelly

 

51

 

Vice President (2007)

R. M. Kruger

  49  

Vice President (2008)

S. R. LaSala

 

64

 

Vice President and General Tax Counsel (2007)

C. W. Matthews

 

64

 

Vice President and General Counsel (1995)

P. T. Mulva

 

57

 

Vice President and Controller (2004)

S. D. Pryor

 

59

 

Vice President (2004)

D. S. Rosenthal

  52  

Vice President - Investor Relations and Secretary (2008)

A. P. Swiger

  52   Vice President (2006)

 

For at least the past five years, Messrs. Cramer, Humphreys, LaSala, Matthews, Mulva 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. Albers was President of ExxonMobil Development Company before becoming Senior Vice President. Mr. Dolan was President of ExxonMobil Chemical Company before becoming Senior Vice President. Mr. Humphreys was Vice President and Controller and then Vice President and Treasurer before becoming Senior Vice President and Treasurer. Mr. Colton was Assistant Treasurer before becoming Vice President—Strategic Planning. Mr. LaSala was Associate General Tax Counsel before becoming Vice President and General Tax Counsel. Mr. Mulva was Vice President—Investor Relations and Secretary before becoming Vice President and Controller. Mr. Rosenthal was Assistant Controller before becoming Vice President—Investor Relations and Secretary.

 

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, 2008.

 

Esso Exploration and Production Chad Inc.

   Duffin

Esso UK Limited

   Swiger

ExxonMobil Chemical Company

   Dolan, Glass, Jr. and Pryor

ExxonMobil Development Company

   Albers and Duffin

ExxonMobil Exploration Company

   Cejka

ExxonMobil Fuels Marketing Company

   Cramer

ExxonMobil Gas & Power Marketing Company

   Colton and Swiger

ExxonMobil Lubricants & Petroleum Specialties Company

   Kelly

ExxonMobil Production Company

   Kruger, Duffin, Rosenthal and Swiger

ExxonMobil Refining & Supply Company

   Dolan, Glass, Jr. and Pryor

 

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

 

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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, 2008  

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, 2008

   44,106,871    71.47    44,106,871       

November, 2008

   34,454,801    74.43    34,454,801       

December, 2008

   39,959,136    78.27    39,959,136       
    
       
      

Total

   118,520,808    74.63    118,520,808    (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. In its most recent earnings release dated January 30, 2009, the Corporation stated that share purchases to reduce shares outstanding are anticipated to equal $7.0 billion through the first quarter of 2009. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.

 

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Item 6.    Selected Financial Data.

 

    Years Ended December 31,

    2008

  2007

  2006

  2005

  2004

   

(millions of dollars, except per share amounts)

Sales and other operating revenue (1)(2)   $ 459,579   $ 390,328   $ 365,467   $ 358,955   $ 291,252

(1) Sales-based taxes included.

  $ 34,508   $ 31,728   $ 30,381   $ 30,742   $ 27,263

(2) Includes amounts for purchases/sales contracts with the same counterparty for 2004-2005.

Net income   $ 45,220   $ 40,610   $ 39,500   $ 36,130   $ 25,330
Net income per common share   $ 8.78   $ 7.36   $ 6.68   $ 5.76   $ 3.91
Net income per common share - assuming dilution   $ 8.69   $ 7.28   $ 6.62   $ 5.71   $ 3.89
Cash dividends per common share   $ 1.55   $ 1.37   $ 1.28   $ 1.14   $ 1.06
Total assets   $ 228,052   $ 242,082   $ 219,015   $ 208,335   $ 195,256
Long-term debt   $ 7,025   $ 7,183   $ 6,645   $ 6,220   $ 5,013

 

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 27, 2009, 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);

   

“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.

 

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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, 2008. Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporation in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

 

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 criteria established in 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, 2008.

 

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2008, 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.

 

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 2009 annual meeting of shareholders (the “2009 Proxy Statement”):

 

   

The section entitled “Election of Directors”;

   

The portion entitled “Section 16(a) Beneficial Ownership Reporting Compliance” of the section entitled “Director and Executive Officer Stock Ownership”;

   

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”.

 

31


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Index to Financial Statements

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 2009 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 2009 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

   67,018,885 (2)(3)   $41.18(3)   162,531,817(3)(4)(5)

Equity compensation plans not approved by security holders

  

0        

  0  

0        

              

Total

  

67,018,885      

 

$41.18  

 

162,531,817        

 

(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 four prior option grants that are still outstanding.

 

(2)   Includes 58,169,384 options granted under the 1993 Incentive Program and 8,849,501 restricted stock units to be settled in shares.

 

(3)   Does not include options that ExxonMobil assumed in the 1999 merger with Mobil Corporation. At year-end 2008, the number of securities to be issued upon exercise of outstanding options under Mobil Corporation plans was 1,823,135, and the weighted-average exercise price of such options $31.70. 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 161,717,617 shares available for award under the 2003 Incentive Program and 814,200 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan.

 

(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 2,500 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 may be forfeited if the director leaves the Board early.

 

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Index to Financial Statements

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

 

Information provided in response to 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 2009 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 2009 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]

 

 

 

 

 

34


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Index to Financial Statements

FINANCIAL SECTION

TABLE OF CONTENTS

 

Business Profile

   36

Financial Summary

   37

Frequently Used Terms

   38

Quarterly Information

   40

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

    

Functional Earnings

   41

Forward-Looking Statements

   42

Overview

   42

Business Environment and Risk Assessment

   42

Review of 2008 and 2007 Results

   44

Liquidity and Capital Resources

   46

Capital and Exploration Expenditures

   49

Taxes

   50

Environmental Matters

   50

Market Risks, Inflation and Other Uncertainties

   50

Recently Issued Statements of Financial Accounting Standards

   52

Critical Accounting Policies

   52

Management’s Report on Internal Control Over Financial Reporting

   56

Report of Independent Registered Public Accounting Firm

   56

Consolidated Financial Statements

    

Statement of Income

   58

Balance Sheet

   59

Statement of Shareholders’ Equity

   60

Statement of Cash Flows

   61

Notes to Consolidated Financial Statements

    

1. Summary of Accounting Policies

   62

2. Accounting Change for Fair Value Measurements

   64

3. Miscellaneous Financial Information

   64

4. Cash Flow Information

   64

5. Additional Working Capital Information

   64

6. Equity Company Information

   65

7. Investments, Advances and Long-Term Receivables

   66

8. Property, Plant and Equipment and Asset Retirement Obligations

   66

9. Accounting for Suspended Exploratory Well Costs

   67

10. Leased Facilities

   69

11. Earnings Per Share

   69

12. Financial Instruments and Derivatives

   70

13. Long-Term Debt

   70

14. Incentive Program

   75

15. Litigation and Other Contingencies

   77

16. Pension and Other Postretirement Benefits

   79

17. Disclosures about Segments and Related Information

   83

18. Income, Sales-Based and Other Taxes

   85

Supplemental Information on Oil and Gas Exploration and Production Activities

   87

Operating Summary

   97

 

35


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Index to Financial Statements

BUSINESS PROFILE

 

Financial


   Earnings After
Income Taxes


    Average Capital
Employed


   Return on
Average Capital
Employed


   Capital and
Exploration
Expenditures


   2008

    2007

    2008

   2007

   2008

   2007

   2008

   2007

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

Upstream

                                                     

United States

   $ 6,243     $ 4,870     $ 14,651    $ 14,026    42.6    34.7    $ 3,334    $ 2,212

Non-U.S.

     29,159       21,627       51,413      49,539    56.7    43.7      16,400      13,512
    


 


 

  

  
  
  

  

Total

   $ 35,402     $ 26,497     $ 66,064    $ 63,565    53.6    41.7    $ 19,734    $ 15,724
    


 


 

  

  
  
  

  

Downstream

                                                     

United States

   $ 1,649     $ 4,120     $ 6,963    $ 6,331    23.7    65.1    $ 1,636    $ 1,128

Non-U.S.

     6,502       5,453       18,664      18,983    34.8    28.7      1,893      2,175
    


 


 

  

  
  
  

  

Total

   $ 8,151     $ 9,573     $ 25,627    $ 25,314    31.8    37.8    $ 3,529    $ 3,303
    


 


 

  

  
  
  

  

Chemical

                                                     

United States

   $ 724     $ 1,181     $ 4,535    $ 4,748    16.0    24.9    $ 441    $ 360

Non-U.S.

     2,233       3,382       9,990      8,682    22.4    39.0      2,378      1,422
    


 


 

  

  
  
  

  

Total

   $ 2,957     $ 4,563     $ 14,525    $ 13,430    20.4    34.0    $ 2,819    $ 1,782
    


 


 

  

  
  
  

  

Corporate and financing

     (1,290 )     (23 )     23,467      26,451    —      —        61      44
    


 


 

  

  
  
  

  

Total

   $ 45,220     $ 40,610     $ 129,683    $ 128,760    34.2    31.8    $ 26,143    $ 20,853
    


 


 

  

  
  
  

  

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

 

Operating


   2008

   2007

     (thousands of barrels daily)

Net liquids production

         

United States

   367    392

Non-U.S.

   2,038    2,224
    
  

Total

   2,405    2,616
    
  
     (millions of cubic feet daily)

Natural gas production available for sale

         

United States

   1,246    1,468

Non-U.S.

   7,849    7,916
    
  

Total

   9,095    9,384
    
  
     (thousands of oil-equivalent barrels daily)

Oil-equivalent production (1)

   3,921    4,180
     (thousands of barrels daily)

Refinery throughput

         

United States

   1,702    1,746

Non-U.S.

   3,714    3,825
    
  

Total

   5,416    5,571
    
  
     (thousands of barrels daily)

Petroleum product sales

         

United States

   2,540    2,717

Non-U.S.

   4,221    4,382
    
  

Total

   6,761    7,099
    
  
     (thousands of metric tons)

Chemical prime product sales

         

United States

   9,526    10,855

Non-U.S.

   15,456    16,625
    
  

Total

   24,982    27,480
    
  

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

 

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FINANCIAL SUMMARY

 

     2008

    2007

    2006

    2005

    2004

 
     (millions of dollars, except per share amounts)  

Sales and other operating revenue (1) (2)

   $ 459,579     $ 390,328     $ 365,467     $ 358,955     $ 291,252  

Earnings

                                        

Upstream

   $ 35,402     $ 26,497     $ 26,230     $ 24,349     $ 16,675  

Downstream

     8,151       9,573       8,454       7,992       5,706  

Chemical

     2,957       4,563       4,382       3,943       3,428  

Corporate and financing

     (1,290 )     (23 )     434       (154 )     (479 )
    


 


 


 


 


Net income

   $ 45,220     $ 40,610     $ 39,500     $ 36,130     $ 25,330  
    


 


 


 


 


Net income per common share

   $ 8.78     $ 7.36     $ 6.68     $ 5.76     $ 3.91  

Net income per common share – assuming dilution

   $ 8.69     $ 7.28     $ 6.62     $ 5.71     $ 3.89  

Cash dividends per common share

   $ 1.55     $ 1.37     $ 1.28     $ 1.14     $ 1.06  

Net income to average shareholders’ equity (percent)

     38.5       34.5       35.1       33.9       26.4  

Working capital

   $ 23,166     $ 27,651     $ 26,960     $ 27,035     $ 17,396  

Ratio of current assets to current liabilities (times)

     1.47       1.47       1.55       1.58       1.40  

Additions to property, plant and equipment

   $ 19,318     $ 15,387     $ 15,462     $ 13,839     $ 11,986  

Property, plant and equipment, less allowances

   $ 121,346     $ 120,869     $ 113,687     $ 107,010     $ 108,639  

Total assets

   $ 228,052     $ 242,082     $ 219,015     $ 208,335     $ 195,256  

Exploration expenses, including dry holes

   $ 1,451     $ 1,469     $ 1,181     $ 964     $ 1,098  

Research and development costs

   $ 847     $ 814     $ 733     $ 712     $ 649  

Long-term debt

   $ 7,025     $ 7,183     $ 6,645     $ 6,220     $ 5,013  

Total debt

   $ 9,425     $ 9,566     $ 8,347     $ 7,991     $ 8,293  

Fixed-charge coverage ratio (times)

     52.2       49. 9       46.3       50.2       36.1  

Debt to capital (percent)

     7.4       7.1       6.6       6.5       7.3  

Net debt to capital (percent) (3)

     (23.0 )     (24.0 )     (20.4 )     (22.0 )     (10.7 )

Shareholders’ equity at year end

   $ 112,965     $ 121,762     $ 113,844     $ 111,186     $ 101,756  

Shareholders’ equity per common share

   $ 22.70     $ 22.62     $ 19.87     $ 18.13     $ 15.90  

Weighted average number of common shares outstanding (millions)

     5,149       5,517       5,913       6,266       6,482  

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

     79.9       80.8       82.1       83.7       85.9  

CORS employees not included above (thousands) (5)

     24.8       26.3       24.3       22.4       19.3  

(1) Sales and other operating revenue includes sales-based taxes of $34,508 million for 2008, $31,728 million for 2007, $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.
(3) Debt net of cash, excluding restricted cash.
(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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Index to Financial Statements

FREQUENTLY USED TERMS

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

CASH FLOW FROM OPERATIONS AND ASSET SALES

Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds from sales of subsidiaries, investments and property, plant and equipment from the Consolidated Statement of Cash Flows. This cash flow reflects 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 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


   2008

   2007

   2006

     (millions of dollars)

Net cash provided by operating activities

   $ 59,725    $ 52,002    $ 49,286

Sales of subsidiaries, investments and property, plant and equipment

     5,985      4,204      3,080
    

  

  

Cash flow from operations and asset sales

   $ 65,710    $ 56,206    $ 52,366
    

  

  

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


   2008

    2007

    2006

 
     (millions of dollars)  

Business uses: asset and liability perspective

                        

Total assets

   $ 228,052     $ 242,082     $ 219,015  

Less liabilities and minority share of assets and liabilities

                        

Total current liabilities excluding notes and loans payable

     (46,700 )     (55,929 )     (47,115 )

Total long-term liabilities excluding long-term debt and equity of minority interests

     (54,404 )     (50,543 )     (45,905 )

Minority share of assets and liabilities

     (6,044 )     (5,332 )     (4,948 )

Add ExxonMobil share of debt-financed equity company net assets

     4,798       3,386       2,808  
    


 


 


Total capital employed

   $ 125,702     $ 133,664     $ 123,855  
    


 


 


Total corporate sources: debt and equity perspective

                        

Notes and loans payable

   $ 2,400     $ 2,383     $ 1,702  

Long-term debt

     7,025       7,183       6,645  

Shareholders’ equity

     112,965       121,762       113,844  

Less minority share of total debt

     (1,486 )     (1,050 )     (1,144 )

Add ExxonMobil share of equity company debt

     4,798       3,386       2,808  
    


 


 


Total capital employed

   $ 125,702     $ 133,664     $ 123,855  
    


 


 


 

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Index to Financial Statements

RETURN ON AVERAGE CAPITAL EMPLOYED

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

 

Return on average capital employed


   2008

    2007

    2006

 
     (millions of dollars)  

Net income

   $ 45,220     $ 40,610     $ 39,500  

Financing costs (after tax)

                        

Gross third-party debt

     (343 )     (339 )     (264 )

ExxonMobil share of equity companies

     (325 )     (204 )     (156 )

All other financing costs – net

     1,485       268       499  
    


 


 


Total financing costs

     817       (275 )     79  
    


 


 


Earnings excluding financing costs

   $ 44,403     $ 40,885     $ 39,421  
    


 


 


Average capital employed

   $ 129,683     $ 128,760     $ 122,573  

Return on average capital employed – corporate total

     34.2 %     31.8 %     32.2 %

 

39


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Index to Financial Statements

QUARTERLY INFORMATION

 

     2008

   2007

   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

     2,468    2,391    2,290    2,472    2,405      2,746    2,668    2,537    2,517    2,616

Refinery throughput

     5,526    5,472    5,354    5,313    5,416      5,705    5,279    5,582    5,717    5,571

Petroleum product sales

     6,821    6,775    6,688    6,761    6,761      7,198    6,973    7,100    7,125    7,099
     (millions of cubic feet daily)

Natural gas production available for sale

     10,229    8,489    7,820    9,849    9,095      10,114    8,733    8,283    10,414    9,384
     (thousands of oil-equivalent barrels daily)

Oil-equivalent production (1)

     4,173    3,806    3,593    4,113    3,921      4,432    4,123    3,918    4,253    4,180
     (thousands of metric tons)

Chemical prime product sales

     6,578    6,718    6,060    5,626    24,982      6,805    6,897    6,729    7,049    27,480

Summarized financial data

                                                     
     (millions of dollars)

Sales and other operating revenue (2)

   $ 113,223    133,776    132,085    80,495    459,579    $ 84,174    95,059    99,130    111,965    390,328

Gross profit (3)

   $ 40,255    43,925    45,901    29,760    159,841    $ 33,907    36,760    36,114    39,914    146,695

Net income

   $ 10,890    11,680    14,830    7,820    45,220    $ 9,280    10,260    9,410    11,660    40,610

Per share data

                                                     
     (dollars per share)

Net income per common share (4)

   $ 2.05    2.25    2.89    1.57    8.78    $ 1.64    1.85    1.72    2.15    7.36

Net income per common share – assuming dilution (4)

   $ 2.03    2.22    2.86    1.55    8.69    $ 1.62    1.83    1.70    2.13    7.28

Dividends per common share

   $ 0.35    0.40    0.40    0.40    1.55    $ 0.32    0.35    0.35    0.35    1.37

Common stock prices

                                                     

High

   $ 94.74    96.12    89.63    83.64    96.12    $ 76.35    86.58    93.66    95.27    95.27

Low

   $ 77.55    84.26    71.51    56.51    56.51    $ 69.02    75.28    78.76    83.37    69.02

(1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(2) Includes amounts for sales-based taxes.
(3) Gross profit equals sales and other operating revenue less estimated costs associated with products sold.
(4) Computed using the average number of shares outstanding during each period. The sum of the four quarters may not add to the full year.

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 546,588 registered shareholders of ExxonMobil common stock at December 31, 2008. At January 31, 2009, the registered shareholders of ExxonMobil common stock numbered 540,892.

On January 28, 2009, the Corporation declared a $0.40 dividend per common share, payable March 10, 2009.

 

40


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Index to Financial Statements

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

 

FUNCTIONAL EARNINGS


   2008

    2007

    2006

     (millions of dollars, except per share amounts)

Net income (U.S. GAAP)

                      

Upstream

                      

United States

   $ 6,243     $ 4,870     $ 5,168

Non-U.S.

     29,159       21,627       21,062

Downstream

                      

United States

     1,649       4,120       4,250

Non-U.S.

     6,502       5,453       4,204

Chemical

                      

United States

     724       1,181       1,360

Non-U.S.

     2,233       3,382       3,022

Corporate and financing

     (1,290 )     (23 )     434
    


 


 

Net income

   $ 45,220     $ 40,610     $ 39,500
    


 


 

Net income per common share

   $ 8.78     $ 7.36     $ 6.68

Net income per common share – assuming dilution

   $ 8.69     $ 7.28     $ 6.62

Special items included in net income

                      

Non-U.S. Upstream

                      

Gain on German natural gas transportation business sale

   $ 1,620     $ —       $ —  

Corporate and financing

                      

Tax-related benefit

   $ —       $ —       $ 410

Valdez litigation

   $ (460 )   $ —       $ —  

 

41


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Index to Financial Statements

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 and uncertain tax positions; 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; political or regulatory events; and other factors discussed herein and in Item 1A of ExxonMobil’s 2008 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 90 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 business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. 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 are utilized 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.

BUSINESS ENVIRONMENT AND RISK ASSESSMENT

Long-Term Business Outlook

By 2030, the world’s population is projected to grow to approximately 8 billion people, or about 1.5 billion more than in 2005. Coincident with this population increase, the Corporation expects worldwide economic growth to average close to 3 percent per year. This combination of population and economic growth is expected to lead to an increase in primary energy demand of approximately 35 percent by 2030 versus 2005 even with substantial efficiency gains. The vast majority (over 90 percent) of the demand increase is expected to occur in developing countries.

As economic progress drives demand higher, the use of more energy-efficient technologies and practices will become increasingly important, leading to a significantly lower level of energy consumption per unit of economic output by 2030. Efficiency gains will result from anticipated improvements in the transportation and power generation sectors, driven by the introduction of new technologies, as well as many other improvements that span the residential, commercial and industrial sectors.

Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by 40 percent from 2005 to 2030. The global growth in transportation demand will be met primarily by oil, which is expected to provide almost 95 percent of all transportation fuel by 2030, down from about 98 percent in 2005, as biofuels and natural gas gain market share.

Demand for electricity around the world will grow significantly through 2030. Consistent with this projection, power generation will remain the largest and fastest-growing segment of global energy demand. Meeting the expected growth in power demand will require a diverse set of energy sources. Coal will retain the largest share, however natural gas, nuclear and renewables are all expected to gain market share.

Liquid fuels provide the largest share of energy supply today due to their availability, affordability and ease of transport. By 2030, global demand for liquids is expected to grow to approximately 108 million barrels of oil-equivalent per day or close to 30 percent more than in 2005. Global demand for liquid fuels will be met by a wide variety of sources. Conventional non-OPEC crude and condensate production is expected to remain relatively flat through 2030. However, growth is expected from a number of supply sources, including biofuels, oil sands and natural gas liquids, as well as crude oil from OPEC countries. While the world’s resource base is sufficient to meet projected demand, access to resources and timely investments will remain critical to meeting global needs.

 

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Increases in natural gas demand in North America, Europe and Asia Pacific will require new sources of supply, primarily from imports. The growing need for natural gas imports will have a dramatic impact on the worldwide liquefied natural gas (LNG) market, which is expected to more than triple in volume by 2030.

The world’s energy mix is highly diverse and will remain so through 2030. Oil is expected to remain the largest source of energy supply at close to 35 percent. Natural gas is expected to grow the fastest of the fossil fuels and overtake coal as the second-largest energy source. Nuclear power is projected to grow significantly, surpassing coal in terms of absolute growth and becoming the fourth-largest fuel source. Hydro and geothermal will also grow, though remain limited by the availability of natural sites. Wind, solar and biofuels are expected to grow at about 9 percent per year on average, the highest growth rate of all fuels, and are projected to reach approximately 2 percent of world energy by 2030.

The Corporation anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply 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 close to $500 billion per year on average, or about $11.7 trillion (measured in 2007 dollars) in total for 2007-2030.

Upstream

ExxonMobil continues to maintain a large portfolio of development and exploration opportunities, which enables the Corporation to be selective, maximizing shareholder value and mitigating political and technical risks. ExxonMobil’s fundamental Upstream business strategies guide our global exploration, development, production, and gas and power marketing activities. These strategies include identifying and pursuing all attractive exploration opportunities, investing in projects that deliver superior returns, maximizing profitability of existing oil and gas production, and capitalizing on growing natural gas and power markets. These strategies are underpinned by a relentless focus on operational excellence, commitment to innovative technologies, development of our employees and investment in the communities in which we operate.

As future development projects bring new production online, the Corporation expects a shift in the geographic mix of its production volumes between now and 2013. Oil and natural gas output from West Africa, the Caspian region, 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 39 percent of the Corporation’s production. By 2013, 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, North America and Asia Pacific.

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, tight gas production and LNG is expected to grow from about 30 percent to over 40 percent of the Corporation’s output between now and 2013. The Corporation’s overall volume capacity outlook, based on projects coming onstream as anticipated, is for production capacity to grow over the period 2009-2013. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, performance of enhanced oil recovery projects, regulatory changes, asset sales, weather events, price effects under production sharing contracts and other factors described in Item 1A of ExxonMobil’s 2008 Form 10-K. Enhanced oil recovery projects extract hydrocarbons from reservoirs in excess of that which may be produced through primary recovery, i.e., through pressure depletion or natural aquifer support. They include the injection of water, gases or chemicals into a reservoir to produce hydrocarbons otherwise unobtainable.

Downstream

ExxonMobil’s Downstream is a large, diversified business with refining and marketing complexes around the world. The Corporation has a strong presence in mature markets in North America and Europe, as well as the growing Asia Pacific region. ExxonMobil’s fundamental Downstream business strategies position the company to deliver long-term growth in shareholder value that is superior to competition across a range of market conditions. These strategies include maintaining best-in-class operations in all aspects of the business, maximizing value from leading-edge technologies, capitalizing on integration with other ExxonMobil businesses, selectively investing for resilient, advantaged returns, leading the industry in efficiency and effectiveness, and providing quality, valued products and services to customers.

ExxonMobil has an ownership interest in 37 refineries, located in 20 countries, with distillation capacity of 6.2 million barrels per day and lubricant basestock manufacturing capacity of about 140 thousand barrels per day. ExxonMobil’s fuels and lubes marketing business portfolios include operations around the world, serving a globally diverse customer base.

The downstream industry environment remains competitive. The industry has experienced a period of robust refining margins, which has encouraged the construction of additional industry capacity. However, over the prior 20-year period, inflation-adjusted refining margins have declined at an average rate of about 1 percent per year. Refining margins are largely driven by differences in commodity prices and 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, diesel 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 Intercontinental Exchange). Prices for these commodities are determined by the global marketplace and are influenced by many factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, seasonal demand, weather and political climate.

 

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Index to Financial Statements

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

 

ExxonMobil’s long-term outlook continues to be that refining margins will generally decline as refineries continue to improve efficiency and, in the near term, new capacity additions outpace the growth in global demand.

In the retail fuels marketing business, ongoing intense competition continues to drive down inflation-adjusted margins by about 3 percent per year. In 2008, ExxonMobil announced its intention to transition out of the direct served (i.e., dealer, company-operated) retail business in U.S. markets and to convert a majority of markets to a branded distributor model. This transition will be a multiyear process.

ExxonMobil’s Downstream capital expenditures remain focused on selective and resilient investments. These investments capitalize on the Corporation’s world-class scale and integration, industry-leading efficiency, leading-edge technology and respected brands, enabling ExxonMobil to take advantage of attractive emerging-growth opportunities around the globe. For example, in 2008, ExxonMobil announced plans to invest over $1 billion in three refineries to increase the supply of cleaner burning diesel by about 140 thousand barrels per day. The company will construct new units and modify existing facilities at its Baton Rouge, La., Baytown, Texas, and Antwerp, Belgium, refineries. ExxonMobil is also participating in an integrated refining, petrochemicals and fuels marketing venture in Fujian, China, with our partners Saudi Aramco, Sinopec and Fujian Province. The manufacturing portion of the venture will expand an existing 80-thousand-barrel-per-day refinery in the Fujian Province to a 240-thousand-barrel-per-day high-conversion facility. The project also includes a new world-scale integrated chemical plant. The project is expected to start up in 2009. The fuels marketing portion of the venture includes approximately 750 retail sites and a network of distribution terminals.

Chemical

Worldwide petrochemical demand decreased in 2008, reflecting the global economic slowdown in the second half of the year. Despite record high feedstock costs, chemical growth continued in the first half of the year fueled by increased demand in Asia Pacific, particularly China. As a result, supply/demand balances supported higher product prices during this period. Demand dropped sharply in the second half of the year, reflecting slower economic growth and broad supply chain inventory de-stocking during rapid feedstock cost declines. With this demand decrease, margins weakened and industry operating rates were cut back.

ExxonMobil benefited from continued operational excellence and a balanced portfolio of products. In addition to being a worldwide supplier of primary petrochemical products, ExxonMobil Chemical also has a number 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 refineries or upstream gas processing facilities, advantaged feedstock capabilities, leading proprietary technology and product application expertise.

REVIEW OF 2008 AND 2007 RESULTS

 

     2008

   2007

   2006

     (millions of dollars)

Net income (U.S. GAAP)

   $ 45,220    $ 40,610    $ 39,500

2008

Net income in 2008 of $45,220 million was a record for the Corporation, up $4,610 million from 2007. Net income for 2008 included an after-tax gain of $1,620 million from the sale of a natural gas transportation business in Germany and after-tax special charges of $460 million related to the Valdez litigation.

2007

Net income in 2007 of $40,610 million was up $1,110 million from 2006. Net income for 2006 included a $410 million gain from the recognition of tax benefits related to historical investments in non-U.S. assets.

Upstream

 

     2008

   2007

   2006

     (millions of dollars)

Upstream

                    

United States

   $ 6,243    $ 4,870    $ 5,168

Non-U.S.

     29,159      21,627      21,062
    

  

  

Total

   $ 35,402    $ 26,497    $ 26,230
    

  

  

2008

Upstream earnings for 2008 totaled $35,402 million, an increase of $8,905 million from 2007, including an after-tax gain of $1,620 million from the sale of a natural gas transportation business in Germany. Record high crude oil and natural gas realizations increased earnings approximately $11.8 billion. Lower sales volumes reduced earnings about $3.7 billion. Higher taxes and increased operating costs decreased earnings approximately $1.5 billion, partially offset by favorable foreign exchange. Oil-equivalent production decreased 6 percent versus 2007, including impacts from lower entitlement volumes, the expropriation of assets in Venezuela and divestments. Excluding these impacts, total oil-equivalent production decreased 3 percent. Liquids production of 2,405 kbd (thousands of barrels per day) decreased 211 kbd from 2007. Production increases from new projects in West Africa were more than offset by field decline, lower entitlement volumes, the expropriation of assets in Venezuela and divestments. Natural gas production of 9,095 mcfd (millions of cubic feet per day) decreased 289 mcfd from 2007. Higher volumes from North Sea, Malaysia and Qatar projects and higher European demand were more than offset by field decline. Earnings from U.S. Upstream operations for 2008 were $6,243 million, an increase of $1,373 million. Earnings outside the U.S. for 2008, including a $1,620 million gain related to the sale of the German natural gas transportation business, were $29,159 million, $7,532 million higher than in 2007.

 

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2007

Upstream earnings for 2007 totaled $26,497 million, an increase of $267 million from 2006. Higher liquids realizations increased earnings approximately $3.1 billion, while lower natural gas realizations decreased earnings about $600 million. Higher operating expenses and unfavorable tax effects reduced earnings about $2.2 billion. Oil-equivalent production decreased 1 percent versus 2006, including the expropriation of assets in Venezuela, divestments, OPEC quota effects, and price and spend impacts on volumes. Excluding these impacts, total oil-equivalent production increased 1 percent. Liquids production of 2,616 kbd decreased 65 kbd from 2006. Production increases from new projects in West Africa and higher Russia volumes were offset by field decline and production sharing contract net interest reductions. Natural gas production of 9,384 mcfd increased 50 mcfd from 2006. Higher volumes from projects in Qatar and the North Sea were mostly offset by mature field decline. Earnings from U.S. Upstream operations for 2007 were $4,870 million, a decrease of $298 million. Earnings outside the U.S. for 2007 were $21,627 million, an increase of $565 million.

Downstream

 

     2008

   2007

   2006

     (millions of dollars)

Downstream

                    

United States

   $ 1,649    $ 4,120    $ 4,250

Non-U.S.

     6,502      5,453      4,204
    

  

  

Total

   $ 8,151    $ 9,573    $ 8,454
    

  

  

2008

Downstream earnings of $8,151 million were $1,422 million lower than in 2007. Lower margins reduced earnings approximately $900 million, as weaker refining margins more than offset stronger marketing margins. Higher operating costs, mainly associated with planned work activity, reduced earnings about $700 million, while unfavorable foreign exchange effects decreased earnings approximately $600 million. Improved refinery operations provided a partial offset, increasing earnings about $800 million. Petroleum product sales of 6,761 kbd decreased from 7,099 kbd in 2007, primarily reflecting asset sales and lower demand. Refinery throughput was 5,416 kbd compared with 5,571 kbd in 2007. U.S. Downstream earnings were $1,649 million, down $2,471 million from 2007. Non-U.S. Downstream earnings of $6,502 million were $1,049 million higher than in 2007.

2007

Downstream earnings totaled $9,573 million, an increase of $1,119 million from 2006. Improved worldwide refining operations increased earnings approximately $800 million, while higher gains on asset sales improved earnings about $900 million. Lower refining margins decreased earnings approximately $600 million. Petroleum product sales of 7,099 kbd decreased from 7,247 kbd in 2006, primarily due to divestment impacts. Refinery throughput was 5,571 kbd compared with 5,603 kbd in 2006. U.S. Downstream earnings of $4,120 million decreased $130 million. Non-U.S. Downstream earnings of $5,453 million were $1,249 million higher than in 2006.

Chemical

 

     2008

   2007

   2006

     (millions of dollars)

Chemical

                    

United States

   $ 724    $ 1,181    $ 1,360

Non-U.S.

     2,233      3,382      3,022
    

  

  

Total

   $ 2,957    $ 4,563    $ 4,382
    

  

  

2008

Chemical earnings totaled $2,957 million, a decrease of $1,606 million from 2007. Lower margins reduced earnings approximately $1.2 billion, while lower volumes decreased earnings about $500 million. Prime product sales were 24,982 kt (thousands of metric tons), a decrease of 2,498 kt from last year. 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 $724 million decreased $457 million. Non-U.S. Chemical earnings of $2,233 million were $1,149 million lower than in 2007.

2007

Chemical earnings totaled $4,563 million, an increase of $181 million from 2006. Higher sales volumes and favorable foreign exchange effects increased earnings approximately $450 million, while lower margins reduced earnings about $325 million. Prime product sales were 27,480 kt, an increase of 130 kt. U.S. Chemical earnings of $1,181 million decreased $179 million. Non-U.S. Chemical earnings of $3,382 million were $360 million higher than in 2006.

 

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Index to Financial Statements

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

 

Corporate and Financing

 

     2008

    2007

    2006

     (millions of dollars)

Corporate and financing

   $ (1,290 )   $ (23 )   $ 434

2008

Corporate and financing expenses of $1,290 million in 2008 increased $1,267 million from 2007, mainly due to charges of $460 million related to the Valdez litigation, net higher taxes and lower interest income.

2007

Corporate and financing expenses were $23 million in 2007, compared to an earnings contribution of $434 million in 2006, which included a $410 million gain from tax benefits related to historical investments in non-U.S. assets.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

 

     2008

    2007

    2006

 
     (millions of dollars)  

Net cash provided by/(used in)

                        

Operating activities

   $ 59,725     $ 52,002     $ 49,286  

Investing activities

     (15,499 )     (9,728 )     (14,230 )

Financing activities

     (44,027 )     (38,345 )     (36,210 )

Effect of exchange rate changes

     (2,743 )     1,808       727  
    


 


 


Increase/(decrease) in cash and cash equivalents

   $ (2,544 )   $ 5,737     $ (427 )
    


 


 


           (Dec. 31)        

Cash and cash equivalents

   $ 31,437     $ 33,981     $ 28,244  

Cash and cash equivalents – restricted

     —         —         4,604  
    


 


 


Total cash and cash equivalents

   $ 31,437     $ 33,981     $ 32,848  
    


 


 


Cash and cash equivalents were $31.4 billion at the end of 2008, $2.5 billion lower than the prior year, reflecting $2.7 billion of foreign exchange reductions from the strengthening of the U.S. dollar in 2008.

Cash and cash equivalents were $34.0 billion at the end of 2007, $5.7 billion higher than the prior year, reflecting a $4.6 billion increase due to the release of the restriction on the restricted cash and cash equivalents and $1.8 billion of positive foreign exchange effects from the weakening of the U.S. dollar in 2007. There were no restricted cash and cash equivalents at the end of 2007 (see note 4). Cash flows from operating, investing and financing activities are discussed below. For additional details, see the Consolidated Statement of Cash Flows.

Although the Corporation could issue long-term debt and has access to short-term liquidity, 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 to ensure that it is secure and readily available to meet the Corporation’s cash requirements and to optimize returns on the cash balances.

To support cash flows in future periods 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. 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 the Corporation’s existing oil and gas fields and without new projects, ExxonMobil’s production is expected to decline at approximately 6 percent per year, 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 net interest in production 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 2008 were $26.1 billion, reflecting the Corporation’s continued active investment program. The Corporation expects annual expenditures to range from $25 billion to $30 billion for the next several years. Actual spending could vary depending on the 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

Cash Flow from Operating Activities

2008

Cash provided by operating activities totaled $59.7 billion in 2008, a $7.7 billion increase from 2007. The major source of funds was net income of $45.2 billion, adjusted for the noncash provision of $12.4 billion for depreciation and depletion, both of which increased. The net effects of lower prices and the timing of collection of accounts receivable and of payments of accounts and other payables and of income taxes payable added to cash provided by operating activities.

2007

Cash provided by operating activities totaled $52.0 billion in 2007, a $2.7 billion increase from 2006. The major source of funds was net income of $40.6 billion, adjusted for the noncash provision of $12.3 billion for depreciation and depletion, both of which increased.

Cash Flow from Investing Activities

2008

Cash used in investing activities netted to $15.5 billion in 2008, $5.8 billion higher than in 2007. Spending for property, plant and equipment of $19.3 billion in 2008 increased $3.9 billion from 2007. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $6.0 billion in 2008 compared to $4.2 billion in 2007, the increase reflecting the sale of the German natural gas transportation business in 2008. Cash used in investing activities in 2008 was higher due to the absence of the $4.6 billion positive cash flow in 2007 from the release of the restriction on the restricted cash and cash equivalents. Net cash used for investments and advances and the change in marketable securities was $1.0 billion lower in 2008.

2007

Cash used in investing activities netted to $9.7 billion in 2007, $4.5 billion lower than in 2006. Spending for property, plant and equipment of $15.4 billion in 2007 was comparable to the prior year. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $4.2 billion in 2007 increased $1.1 billion, reflecting a higher level of asset sales in the Downstream business. Additions from the release of the restriction on the restricted cash and cash equivalents were $4.6 billion. Net investments and advances and net additions to marketable securities were $1.3 billion higher in 2007.

Cash Flow from Financing Activities

2008

Cash used in financing activities was $44.0 billion in 2008, an increase of $5.7 billion from 2007, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.55 per share from $1.37 per share and totaled $8.1 billion, a pay-out of 18 percent. Total consolidated short-term and long-term debt decreased $0.2 billion to $9.4 billion at year-end 2008.

Shareholders’ equity decreased $8.8 billion in 2008, to $113.0 billion. Net income of $45.2 billion, reduced by distributions to ExxonMobil shareholders of $8.1 billion of dividends and $32.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding, added to shareholders’ equity. Shareholders’ equity, and net assets and liabilities, decreased $6.8 billion, representing the foreign exchange translation effects of generally weaker foreign currencies at the end of 2008 on ExxonMobil’s operations outside the United States. The change in the funded status of the postretirement benefits reserves in 2008 lowered shareholders’ equity by $5.1 billion.

During 2008, Exxon Mobil Corporation purchased 434 million shares of its common stock for the treasury at a gross cost of $35.7 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 7.5 percent from 5,382 million at the end of 2007 to 4,976 million at the end of 2008. 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.

2007

Cash used in financing activities was $38.3 billion, an increase of $2.1 billion from 2006, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.37 per share from $1.28 per share and totaled $7.6 billion, a payout of 19 percent. Total consolidated short-term and long-term debt increased $1.2 billion to $9.6 billion at year-end 2007.

Shareholders’ equity increased $7.9 billion in 2007, to $121.8 billion, reflecting $40.6 billion of net income reduced by distributions to ExxonMobil shareholders of $7.6 billion of dividends and $28.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding. Shareholders’ equity, and net assets and liabilities, increased $4.2 billion, representing the foreign exchange translation effects of stronger foreign currencies at the end of 2007 on ExxonMobil’s operations outside the United States.

During 2007, Exxon Mobil Corporation purchased 386 million shares of its common stock for the treasury at a gross cost of $31.8 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 6.1 percent from 5,729 million at the end of 2006 to 5,382 million at the end of 2007. Purchases were made in both the open market and through negotiated transactions.

 

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Index to Financial Statements

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

 

Commitments

Set forth below is information about the outstanding commitments of the Corporation’s consolidated subsidiaries at December 31, 2008. 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


   2009

   2010-
2013


   2014
and
Beyond


   Total

     (millions of dollars)

Long-term debt (1)

   13    $ —      $ 3,175    $ 3,850    $ 7,025

– Due in one year (2)

          368      —        —        368

Asset retirement obligations (3)

   8      360      1,474      3,518      5,352

Pension and other postretirement obligations (4)

   16      5,502      3,718      12,338      21,558

Operating leases (5)

   10      2,278      6,126      2,784      11,188

Unconditional purchase obligations (6)

   15      456      1,161      654      2,271

Take-or-pay obligations (7)

          1,125      4,067      4,821      10,013

Firm capital commitments (8)

          9,937      9,131      1,778      20,846

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. The table also excludes unrecognized tax benefits totaling $5.0 billion as of December 31, 2008, because the Corporation is unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits can be found in note 18, Income, Sales-Based and Other Taxes.

Notes:

 

(1) Includes capitalized lease obligations of $380 million.
(2) The amount due in one year is included in notes and loans payable of $2,400 million (note 5).
(3) The fair 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 2009 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 $2,271 million mainly pertain to pipeline throughput agreements and include $1,651 million of obligations to equity companies. The present value of the total commitments, which excludes imputed interest of $423 million, was $1,848 million.
(7) Take-or-pay obligations are noncancelable, long-term commitments for goods and services other than UPOs. The undiscounted obligations of $10,013 million mainly pertain to manufacturing supply, pipeline and terminaling agreements and include $537 million of obligations to equity companies. The present value of the total commitments, which excludes imputed interest of $2,704 million, totaled $7,309 million.
(8) Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $20.8 billion. These commitments were primarily associated with Upstream projects outside the U.S., of which $9.3 billion was associated with projects in West Africa and Kazakhstan. 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, 2008, for $7,847 million, primarily relating to guarantees for notes, loans and performance under contracts (note 15). Included in this amount were guarantees by consolidated affiliates of $6,102 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, 2008

     Equity
Company
Obligations


   Other
Third-Party
Obligations


   Total

     (millions of dollars)

Total guarantees

   $ 6,102    $ 1,745    $ 7,847

 

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Financial Strength

On December 31, 2008, unused credit lines for short-term financing totaled approximately $5.3 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 & Poor’s (AAA) and Moody’s (Aaa), a rating it has sustained for 90 years.

 

     2008

  2007

  2006

Fixed-charge coverage ratio (times)

   52.2   49.9   46.3

Debt to capital (percent)

   7.4   7.1   6.6

Net debt to capital (percent)

   (23.0)   (24.0)   (20.4)

Credit rating

   AAA/Aaa   AAA/Aaa   AAA/Aaa

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

Litigation

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 the compensatory claims have been resolved and paid. All of the punitive damage claims were consolidated in the civil trial that began in 1994. On June 25, 2008, the U.S. Supreme Court vacated the $2.5 billion punitive damage award previously entered by the Ninth Circuit Court of Appeals and remanded the case to the Circuit Court with an instruction that punitive damages in the case may not exceed a maximum amount of $507.5 million. Exxon Mobil Corporation recorded an after-tax charge of $290 million in the second quarter of 2008, reflecting the maximum amount of the punitive damages. The parties have filed briefs in the Ninth Circuit Court of Appeals on the issue of post-judgment interest and recovery of costs. Exxon Mobil Corporation recorded an after-tax charge of $170 million in the third quarter of 2008, reflecting its estimate of the resolution of those issues.

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 beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.

Other Contingencies

In accordance with a nationalization decree issued by Venezuela’s president in February 2007, by May 1, 2007, a subsidiary of the Venezuelan National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. This Project had been operated and owned by ExxonMobil affiliates holding a 41.67 percent ownership interest in the Project. The decree also required conversion of the Cerro Negro Project into a “mixed enterprise” and an increase in PdVSA’s or one of its affiliate’s ownership interest in the Project, with the stipulation that if ExxonMobil refused to accept the terms for the formation of the mixed enterprise within a specified period of time, the government would “directly assume the activities” carried out by the joint venture. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.

On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes. An affiliate of ExxonMobil has also filed an arbitration under the rules of the International Chamber of Commerce against PdVSA and a PdVSA affiliate for breach of their contractual obligations under certain Cerro Negro Project agreements. At this time, the net impact of this matter on the Corporation’s consolidated financial results cannot be reasonably estimated. However, the Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial condition. ExxonMobil’s remaining net book investment in Cerro Negro producing assets is about $750 million.

CAPITAL AND EXPLORATION EXPENDITURES

 

     2008

   2007

     U.S.

   Non-U.S.

   U.S.

   Non-U.S.

     (millions of dollars)

Upstream (1)

   $ 3,334    $ 16,400    $ 2,212    $ 13,512

Downstream

     1,636      1,893      1,128      2,175

Chemical

     441      2,378      360      1,422

Other

     61      —        44      —  
    

  

  

  

Total

   $ 5,472    $ 20,671    $ 3,744    $ 17,109
    

  

  

  

 

(1) Exploration expenses included.

Capital and exploration expenditures in 2008 were $26.1 billion, reflecting the Corporation’s continued active investment program. The Corporation expects annual expenditures to range from $25 billion to $30 billion for the next several years. Actual spending could vary depending on the progress of individual projects.

Upstream spending of $19.7 billion in 2008 was up 26 percent from 2007, mainly due to increased project and exploration expenditures. During the past three years, Upstream capital and exploration expenditures averaged $17.2 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

 

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

 

Downstream totaled $3.5 billion in 2008, an increase of $0.2 billion from 2007, due to higher environmental expenditures. Chemical 2008 capital expenditures of $2.8 billion were up $1.0 billion from 2007 due to increased investment in Asia Pacific to meet demand growth.

TAXES

 

     2008

    2007

    2006

 
     (millions of dollars)  

Income taxes

   $ 36,530     $ 29,864     $ 27,902  

Sales-based taxes

     34,508       31,728       30,381  

All other taxes and duties

     45,223       44,091       42,393  
    


 


 


Total

   $ 116,261     $ 105,683     $ 100,676  
    


 


 


Effective income tax rate

     47 %     44 %     43 %

2008

Income, sales-based and all other taxes totaled $116.3 billion in 2008, an increase of $10.6 billion or 10 percent from 2007. Income tax expense, both current and deferred, was $36.5 billion, $6.7 billion higher than 2007, reflecting higher pre-tax income in 2008. A higher share of total income from the non-U.S. Upstream segment in 2008 increased the effective tax rate to 47 percent compared to 44 percent in 2007. Sales-based and all other taxes and duties of $79.7 billion in 2008 increased $3.9 billion from 2007, reflecting higher prices.

2007

Income, sales-based and all other taxes totaled $105.7 billion in 2007, an increase of $5.0 billion or 5 percent from 2006. Income tax expense, both current and deferred, was $29.9 billion, $2.0 billion higher than 2006, reflecting higher pre-tax income in 2007. The effective tax rate was 44 percent in 2007, compared to 43 percent in 2006. Sales-based and all other taxes and duties of $75.8 billion in 2007 increased $3.0 billion from 2006, reflecting higher prices.

ENVIRONMENTAL MATTERS

Environmental Expenditures

 

     2008

   2007

     (millions of dollars)

Capital expenditures

   $ 2,485    $ 1,525

Other expenditures

     2,730      2,272
    

  

Total

   $ 5,215    $ 3,797
    

  

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 2008 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $5.2 billion. The total cost for such activities is expected to remain in this range in 2009 and 2010 (with capital expenditures approximately 50 percent of the total).

Environmental Liabilities

The Corporation accrues 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 2008 for environmental liabilities were $507 million ($432 million in 2007) and the balance sheet reflects accumulated liabilities of $884 million as of December 31, 2008, and $916 million as of December 31, 2007.

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 ($195 million for 2008). Over time, the liabilities are accreted for the increase in their present value, with this effect included in expenses ($335 million in 2008). Consolidated company expenditures for asset retirement obligations in 2008 were $258 million and the ending balance of the obligations recorded on the balance sheet at December 31, 2008, totaled $5,352 million.

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

 

Worldwide Average Realizations (1)


   2008

   2007

   2006

Crude oil and NGL ($/barrel)

   $ 89.32    $ 66.02    $ 58.34

Natural gas ($/kcf)

     7.54      5.29      6.08

 

(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, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $375 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 $175 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 broad indicators of changes in the earnings experienced in any particular period.

 

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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 & 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.

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 investments 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.

The Corporation has an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the Corporation’s strategic objectives. The result is an efficient capital base, and the Corporation has seldom had 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 on its short-term debt and the portion of long-term debt that carries 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 2008 and 2007. During 2008, credit markets tightened and the global economy slowed. The Corporation is not dependent on the credit markets to fund current operations. However, some joint-venture partners are dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects.

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 many major countries of operation increased in 2008 versus the relatively low rates in recent years, and the associated impact on non-energy costs has generally been mitigated 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 works to counter upward pressure on costs through its economies of scale in global procurement and its efficient project management practices.

 

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

 

RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 160 (FAS 160), “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51.” FAS 160 changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity.

FAS 160 must be adopted by the Corporation no later than January 1, 2009. FAS 160 requires retrospective adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of FAS 160 will be applied prospectively. The Corporation does not expect the adoption of FAS 160 to have a material impact on the Corporation’s financial statements.

Revisions to the Earnings Per Share Calculation

In 2008, the FASB issued a Staff Position (FSP) on the Emerging Issues Task Force (EITF) Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities.” The FSP clarified that all unvested share-based payment awards that contain nonforfeitable rights to dividends should be included in the basic Earnings Per Share (EPS) calculation. The FSP will be effective for first quarter 2009 reporting. The implementation of this standard for the Corporation will result in changes in the calculation of basic and diluted EPS that are not expected to be material. Prior-year EPS numbers will be adjusted retrospectively on a consistent basis. This standard will not affect the consolidated financial position or 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. 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 include both 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 reporting as proved.

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.

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. We understand that the use of December 31 prices and costs is intended to provide a point in time measure to calculate reserves and to enhance comparability between companies. However, the use of year-end prices for reserves estimation introduces short-term price volatility into the process, which

 

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is inconsistent with the long-term nature of the upstream business, since annual adjustments are required based on prices occurring on a single day. As a result, the use of prices from a single date is not relevant to the investment decisions made by the Corporation.

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 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.

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. Volumes are based on individual field production profiles, which are updated annually. 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 consolidated financial statements. The standardized measure of discounted future cash flows is based on the year-end 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.

 

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

 

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 2008 are disclosed in note 9 to the financial statements.

Consolidations

The Consolidated Financial Statements include the accounts of those 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, advances and long-term receivables”; 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.

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. Pension and Other Postretirement Benefits (note 16) 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 those 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 as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2008 was 9.0 percent. The 10-year and 20-year actual returns on U.S. pension plan assets are 5 percent and 9 percent, respectively. 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

 

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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 long-term rate of return on assets would increase annual pension expense by approximately $90 million before tax.

Differences between actual returns on fund assets and 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.

Litigation Contingencies

A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation 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.

Tax Contingencies

The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.

GAAP requires recognition and measurement of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns. The benefit of an uncertain tax position can only be recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken in an income tax return and the amount recognized in the financial statements. The Corporation’s unrecognized tax benefits and a description of open tax years are summarized in note 18.

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 countries with a history of high inflation (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 are primarily in Asia, West Africa, 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; the history of inflation in the country; 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 criteria established in 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, 2008.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2008, as stated in their report included in the Financial Section of this report.

 

 

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:

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, 2008, and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Corporation’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Corporation’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

 

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As discussed in Note 18 to the consolidated financial statements, the Corporation changed its method of accounting for uncertainty in income taxes in 2007.

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 27, 2009

 

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CONSOLIDATED STATEMENT OF INCOME

 

     Note
Reference
Number


   2008

   2007

   2006

          (millions of dollars)

Revenues and other income

                         

Sales and other operating revenue (1)

        $ 459,579    $ 390,328    $ 365,467

Income from equity affiliates

   6      11,081      8,901      6,985

Other income (2)

          6,699      5,323      5,183
         

  

  

Total revenues and other income

        $ 477,359    $ 404,552    $ 377,635
         

  

  

Costs and other deductions

                         

Crude oil and product purchases

        $ 249,454    $ 199,498    $ 182,546

Production and manufacturing expenses

          37,905      31,885      29,528

Selling, general and administrative expenses

          15,873      14,890      14,273

Depreciation and depletion

          12,379      12,250      11,416

Exploration expenses, including dry holes

          1,451      1,469      1,181

Interest expense

          673      400      654

Sales-based taxes (1)

   18      34,508      31,728      30,381

Other taxes and duties

   18      41,719      40,953      39,203

Income applicable to minority interests

          1,647      1,005      1,051
         

  

  

Total costs and other deductions

        $ 395,609    $ 334,078    $ 310,233
         

  

  

Income before income taxes

        $ 81,750    $ 70,474    $ 67,402

Income taxes

   18      36,530      29,864      27,902
         

  

  

Net income

        $ 45,220    $ 40,610    $ 39,500
         

  

  

Net income per common share (dollars)

   11    $ 8.78    $ 7.36    $ 6.68

Net income per common share – assuming dilution (dollars)

   11    $ 8.69    $ 7.28    $ 6.62

 

(1) Sales and other operating revenue includes sales-based taxes of $34,508 million for 2008, $31,728 million for 2007 and $30,381 million for 2006.
(2) Other income for 2008 includes a $62 million gain from the sale of a non-U.S. investment and a related $143 million foreign exchange loss.

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
2008


    Dec. 31
2007


 
          (millions of dollars)  

Assets

                     

Current assets

                     

Cash and cash equivalents

        $ 31,437     $ 33,981  

Marketable securities

          570       519  

Notes and accounts receivable, less estimated doubtful amounts

   5      24,702       36,450  

Inventories

                     

Crude oil, products and merchandise

   3      9,331       8,863  

Materials and supplies

          2,315       2,226  

Other current assets

          3,911       3,924  
         


 


Total current assets

        $ 72,266     $ 85,963  

Investments, advances and long-term receivables

   7      28,556       28,194  

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

   8      121,346       120,869  

Other assets, including intangibles, net

          5,884       7,056  
         


 


Total assets

        $ 228,052     $ 242,082  
         


 


Liabilities

                     

Current liabilities

                     

Notes and loans payable

   5    $ 2,400     $ 2,383  

Accounts payable and accrued liabilities

   5      36,643       45,275  

Income taxes payable

          10,057       10,654  
         


 


Total current liabilities

        $ 49,100     $ 58,312  

Long-term debt

   13      7,025       7,183  

Postretirement benefits reserves

   16      20,729       13,278  

Deferred income tax liabilities

   18      19,726       22,899  

Other long-term obligations

          13,949       14,366  

Equity of minority interests

          4,558       4,282  
         


 


Total liabilities

        $ 115,087     $ 120,320  
         


 


Commitments and contingencies

   15                 

Shareholders’ equity

                     

Common stock without par value

        $ 5,314     $ 4,933  

(9,000 million shares authorized, 8,019 million shares issued)

                     

Earnings reinvested

          265,680       228,518  

Accumulated other comprehensive income

                     

Cumulative foreign exchange translation adjustment

          1,146       7,972  

Postretirement benefits reserves adjustment

          (11,077 )     (5,983 )

Common stock held in treasury (3,043 million shares in 2008 and 2,637 million shares in 2007)

          (148,098 )     (113,678 )
         


 


Total shareholders’ equity

        $ 112,965     $ 121,762  
         


 


Total liabilities and shareholders’ equity

        $ 228,052     $ 242,082  
         


 


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

 

     Note
Reference
Number


   2008

    2007

    2006

      Shareholders’
Equity


    Comprehensive
Income


    Shareholders’
Equity


    Comprehensive
Income


    Shareholders’
Equity


    Comprehensive
Income
(1)


          (millions of dollars)

Common stock

                                                   

At beginning of year

        $ 4,933             $ 4,786             $ 4,477        

Restricted stock amortization

          618               531               480        

Tax benefits related to stock-based awards

          315               113               169        

Cumulative effect of accounting change

   18      —                 (55 )             —          

Other

          (552 )             (442 )             (340 )      
         


         


         


     

At end of year

        $ 5,314             $ 4,933             $ 4,786        
         


         


         


     

Earnings reinvested

                                                   

At beginning of year

          228,518               195,207               163,335        

Net income for the year

          45,220     $ 45,220       40,610     $ 40,610       39,500     $ 39,500

Cumulative effect of accounting change

   18      —                 322               —          

Dividends – common shares

          (8,058 )             (7,621 )             (7,628 )      
         


         


         


     

At end of year

        $ 265,680             $ 228,518             $ 195,207        
         


         


         


     

Accumulated other comprehensive income

                                                   

At beginning of year

          1,989               (2,762 )             (1,279 )      

Foreign exchange translation adjustment

          (6,964 )     (6,964 )     4,239       4,239       2,754       2,754

Adjustment for foreign exchange translation loss included in net income

          138       138       —         —         —         —  

Postretirement benefits reserves adjustment

   16      (5,853 )     (5,853 )     (326 )     (326 )     (6,495 )     —  

Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs

   16      759       759       838       838       —         —  

Minimum pension liability adjustment

          —         —         —         —         2,258       749
         


         


         


     

At end of year

        $ (9,931 )           $ 1,989             $ (2,762 )      
         


 


 


 


 


 

Total

                $ 33,300             $ 45,361             $ 43,003
                 


         


         

Common stock held in treasury

                                                   

At beginning of year

          (113,678 )             (83,387 )             (55,347 )      

Acquisitions, at cost

          (35,734 )             (31,822 )             (29,558 )      

Dispositions

          1,314               1,531               1,518        
         


         


         


     

At end of year

        $ (148,098 )           $ (113,678 )           $ (83,387 )      
         


         


         


     

Shareholders’ equity at end of year

        $ 112,965             $ 121,762             $ 113,844        
         


         


         


     
     Share Activity

        2008

          2007

          2006

     
   (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

          (2,637 )             (2,290 )             (1,886 )      

Acquisitions

          (434 )             (386 )             (451 )      

Dispositions

          28               39               47        
         


         


         


     

At end of year

          (3,043 )             (2,637 )             (2,290 )      
         


         


         


     

Common shares outstanding at end of year

          4,976               5,382               5,729        
         


         


         


     

 

(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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CONSOLIDATED STATEMENT OF CASH FLOWS

 

     Note
Reference
Number


   2008

    2007

    2006

 
          (millions of dollars)  

Cash flows from operating activities

                             

Net income

                             

Accruing to ExxonMobil shareholders

        $ 45,220     $ 40,610     $ 39,500  

Accruing to minority interests

          1,647       1,005       1,051  

Adjustments for noncash transactions

                             

Depreciation and depletion

          12,379       12,250       11,416  

Deferred income tax charges/(credits)

          1,399       124       1,717  

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

          57       (1,314 )     (1,787 )

Other long-term obligation provisions in excess of/(less than) payments

          (63 )     1,065       (666 )

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

          921       (714 )     (579 )

Changes in operational working capital, excluding cash and debt

                             

Reduction/(increase) – Notes and accounts receivable

          8,641       (5,441 )