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The following is an excerpt from a 10-K SEC Filing, filed by EXXON MOBIL CORP on 2/27/2009.
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EXXON MOBIL CORP - 10-K - 20090227 - PART_I

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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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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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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Index to Financial Statements

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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Index to Financial Statements

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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Index to Financial Statements

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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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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