EX-99 2 d66829exv99.htm EXXON MOBIL CORPORATION 2008 FINANCIAL AND OPERATING REVIEW exv99
Table of Contents

EXHIBIT 99
Overview
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CONTENTS
   
   
   1-17 
 
   
   18-21 
 
   
   22-28 
 
   
   29 
 
   
   30-71 
 
   
   72-87 
 
   
   88-95 
 
   
   96-99 
 
   
   100 
 
   
  Inside Back Cover 
The term Upstream refers to exploration, development, production, and gas and power marketing. Downstream refers to the refining and marketing of petroleum products such as motor fuels and lubricants.
Projections, targets, expectations, estimates, and business plans in this report are forward-looking statements. Actual future results, including demand growth and energy mix; capacity growth; the impact of new technologies; capital expenditures; project plans, dates, and capacities; production rates and resource recoveries; and efficiency gains and cost savings could differ materially due to, for example, changes in oil and gas prices or other market conditions affecting the oil and gas industry; reservoir performance; timely completion of development projects; war and other political or security disturbances; changes in law or government regulation; the actions of competitors; unexpected technological developments; the occurrence and duration of economic recessions; the outcome of commercial negotiations; unforeseen technical difficulties; and other factors discussed in this report and in Item 1A of ExxonMobil’s most recent Form 10-K.
Definitions of certain financial and operating measures and other terms used in this report are contained in the section titled “Frequently Used Terms” on pages 96 through 99. In the case of financial measures, the definitions also include information required by SEC Regulation G to the extent we believe applicable.
“Factors Affecting Future Results” and “Frequently Used Terms” are also posted on our Web site and are updated from time to time.
Prior years’ data have been reclassified in certain cases to conform to the 2008 presentation basis.



 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
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Meeting the world’s fundamental and growing need for energy is a massive undertaking.
Today our industry faces the dual challenges of providing the energy needed for meeting demand growth while at the same time reducing our environmental impact. Technological innovation will be critical in solving these challenges.
It is vital that we find solutions because energy is required for economic growth, which lifts the standard of living for people all over the world. At the same time, we need to address concerns about rising greenhouse gas emissions.
Taking on the world’s toughest energy challenges.
Every day, employees at ExxonMobil are committed to the pursuit of operational excellence. We do this by delivering safe, reliable operations, improving energy efficiency, and maintaining strong business controls.
 
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We believe that maximizing the value of resources – through disciplined investments, developing breakthrough technologies, improving processes, and integrated operations – generates the most benefit for resource owners, society, and our shareholders.
Our long-term success also depends on promoting the development of our employees and the communities in which we operate, as well as helping to prepare today’s students to take on tomorrow’s challenges.
For over 125 years ExxonMobil has maintained its commitment to taking on the world’s toughest energy challenges while delivering superior financial results to our shareholders.
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Rex W. Tillerson, Chairman and CEO


 


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  FINANCIAL HIGHLIGHTS   2008     2007     2006     2005     2004  
(millions of dollars, unless noted)
                                       
Sales and other operating revenue(1)(2)
    459,579       390,328       365,467       358,955       291,252  
Net income
    45,220       40,610       39,500       36,130       25,330  
Cash flow from operations and asset sales(3)
    65,710       56,206       52,366       54,174       43,305  
Capital and exploration expenditures(3)
    26,143       20,853       19,855       17,699       14,885  
Cash dividends to ExxonMobil shareholders
    8,058       7,621       7,628       7,185       6,896  
Common stock purchases (gross)
    35,734       31,822       29,558       18,221       9,951  
Research and development costs
    847       814       733       712       649  
Cash and cash equivalents at year end(4)
    31,437       33,981       28,244       28,671       18,531  
Total assets at year end
    228,052       242,082       219,015       208,335       195,256  
Total debt at year end
    9,425       9,566       8,347       7,991       8,293  
Shareholders’ equity at year end
    112,965       121,762       113,844       111,186       101,756  
Average capital employed(3)
    129,683       128,760       122,573       116,961       107,339  
Share price at year end (dollars)
    79.83       93.69       76.63       56.17       51.26  
Market valuation at year end
    397,239       504,220       438,990       344,491       328,128  
Regular employees at year end (thousands)
    79.9       80.8       82.1       83.7       85.9  
         
                                         
  KEY FINANCIAL RATIOS   2008     2007     2006     2005     2004  
Net income per common share (dollars)
    8.78       7.36       6.68       5.76       3.91  
Net income per common share – assuming dilution (dollars)
    8.69       7.28       6.62       5.71       3.89  
Return on average capital employed(3) (percent)
    34.2       31.8       32.2       31.3       23.8  
Net income to average shareholders’ equity (percent)
    38.5       34.5       35.1       33.9       26.4  
Debt to capital(5) (percent)
    7.4       7.1       6.6       6.5       7.3  
Net debt to capital(6) (percent)
    (23.0)       (24.0)       (20.4)       (22.0)       (10.7)  
Ratio of current assets to current liabilities (times)
    1.47       1.47       1.55       1.58       1.40  
Fixed charge coverage (times)
    52.2                  49.9       46.3       50.2       36.1  
         
 
(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)   See Frequently Used Terms on pages 96 through 99.
 
(4)   Excluding restricted cash of $4,604 million in 2006, 2005, and 2004.
 
(5)   Debt includes short- and long-term debt. Capital includes short- and long-term debt, shareholders’ equity, and minority interests.
 
(6)   Debt net of cash and cash equivalents, excluding restricted cash.














 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
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BUSINESS MODEL
ExxonMobil has a consistent and straightforward business model that combines our long-term perspective, disciplined approach to capital investment, and focus on operational excellence to grow shareholder value. We identify, develop, and execute projects using global best practices that ensure project returns will be resilient across a range of economic scenarios. We operate our facilities using proven management systems to achieve operational excellence. As a result, we consistently generate more income from a highly efficient capital base, as demonstrated by our superior return on average capital employed. We deliver industry-leading financial and operating results that grow long-term shareholder value.
ExxonMobil’s superior performance demonstrates
the strength of our long-term business model.
(FLOW CHART)


 
Superior 2008 Results
 
Workforce safety performance continues to lead industry.
 
Record earnings of $45.2 billion, with strong performance in each of our business functions.
 
Annual dividend per share growth of 13 percent versus 2007, the 26th consecutive year of
dividend per share increases.
 
Total shareholder distributions of $40.1 billion, an increase of $4.4 billion versus 2007.
 
Industry-leading return on average capital employed of 34 percent.
 
Start-up of eight major Upstream projects.
 
Total liquids production and natural gas production available for sale of 3.9 million oil-equivalent barrels per day.
 
  Replaced 103 percent of production with proved oil and gas reserve additions of 1.5 billion oil-equivalent barrels, including asset sales and excluding year-end price/cost effects.
 

Record Earnings in 2008
Functional Earnings and Net Income
(BAR GRAPH)
Total Shareholder Returns(1)
(BAR GRAPH)
(1) Reflects data through December 31, 2008.
(2) Royal Dutch Shell, BP, and Chevron values are calculated on a consistent basis with ExxonMobil, based on public information.



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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW

Business Strategies
ExxonMobil’s fundamental strategies are key to achieving sustained, outstanding performance in all aspects of our business. These strategies are not new; they have been tested and proven over decades, spanning the highs and lows of prior business cycles. Through the superior execution of these strategies, ExxonMobil is able to meet the challenge of providing reliable, affordable energy in a responsible manner while delivering superior returns for our shareholders.
Operate in a Safe and Environmentally Responsible Manner
ExxonMobil’s long-term safety performance leads the industry. Our commitment to safety, security, health, and the environment creates a solid foundation for superior results in all aspects of our business. ExxonMobil’s senior management and employees are committed to the goal of creating an incident-free workplace and our culture reflects this objective.
ExxonMobil drives continuous improvement in environmental performance with the goal of reducing incidents with environmental impact to zero. We conduct business using an approach that is compatible with both the environmental and economic needs of the communities in which we operate.
Uphold High Standards
ExxonMobil adheres to all applicable laws and regulations as a minimum standard, and, when requirements do not exist, we apply responsible standards to our operations.
We believe that a well-founded reputation for high ethical standards, strong business controls, and good corporate governance is a priceless corporate asset. This means that how we achieve results is as important as the results themselves. We choose the course of highest integrity in all of our business interactions.
Directors, officers, and employees must comply with our Standards of Business Conduct.
Invest with Discipline
The energy industry is a long-term business that requires decisions to be made with a time horizon that is measured in decades rather than months or years and that spans multiple business cycles.
Projects are tested over a range of economic scenarios to ensure that risks are properly identified, evaluated, and managed. This approach enables superior investment returns through the business cycle.
Our proven project management system incorporates best practices developed around the world. Emphasis on the early phases of concept selection and effective project execution results in investments that maximize resource and asset value. We complete a rigorous reappraisal of all major projects and incorporate learnings into future project planning and design, further strengthening our capabilities.
Differentiate with Proprietary Technology
Technology is vital to meeting the world’s growing demand for energy. Technological innovation creates resource opportunities by delivering cost-effective solutions in challenging environments, and enables the development of high-performance products and improved manufacturing processes.
ExxonMobil has a long-standing commitment to fundamental research to develop and grow our technical capabilities and to deliver advantaged technologies for all of our businesses. We have a wide array of research programs designed to meet the needs identified in our functional businesses. Over the past five years, we have invested more than $3.7 billion in research and development. Our global functional organization enables rapid deployment of new technologies to ensure early value capture.
Pursue Operational Excellence
Operations safety and integrity are integral to the successful execution of ExxonMobil’s business strategies. The objective of operational excellence is embedded in our company


 
ROCE Leadership
Annual Return on Average Capital Employed
(LINE CHART)
Functional Capex Distribution
(BAR CHART)


(1) Royal Dutch Shell, BP, and Chevron values are estimated on a consistent basis with ExxonMobil, based on public information.


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
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culture and drives continuous improvements in all areas of our business.
ExxonMobil has developed a wide range of management and operating systems that address critical aspects of our business, including: ethics, safety, corporate governance, security, health, environmental performance, operations reliability, business controls, project investment and execution, energy efficiency, profit improvement, and external affairs. The disciplined application of these management and operating systems, deployed through our functional organization, has consistently delivered superior results.
Optimize Results Through Functional Diversity and Integration
ExxonMobil’s business portfolio and level of global integration are unique in our industry. Our portfolio of assets provides advantages in scale, geographic diversity, and business mix, and mitigates risks that arise from changes in commodity prices, product margins, and business cycles.
Through integration we are able to capture new opportunities and deliver greater value than any of our businesses could achieve on a stand-alone basis. The combination of our global scale and integration across our business gives ExxonMobil a competitive advantage that is difficult to replicate.
Increase Efficiency Through Our Global Functional Organization
ExxonMobil’s global functional organization is fundamental to our ongoing success. Developed over many years, it is built on the common standards, processes, and culture of the company, and generates a unique competitive advantage.
Our organizational structure drives senior management involvement in all major decisions and ensures consistent global execution of our business processes. We continue to discover new ways to leverage the approach and deliver increased value.
Attract and Retain Exceptional People
Delivering outstanding performance requires exceptional people. Our goal is to develop our employees to have the highest technical and leadership capabilities in the industry. We focus on merit-based, long-term career development and are committed to maintaining a diverse workforce. We recruit talented people from around the world and provide them with formal training and a broad range of global experiences to develop them into the next generation of company leaders. Investing in our people creates a sustainable source of competitive advantage.
Enhance Community Development
ExxonMobil has a long tradition of making a positive contribution to the communities and economies in which we operate through programs that seek to foster social and economic development including health, education, and infrastructure. We partner with local institutions, nongovernmental organizations, governments, and development agencies to design our community investment programs. Through the ExxonMobil Foundation, we provide grants to fund projects in areas such as our two signature initiatives – the Africa Health Initiative and the Educating Women and Girls Initiative.
Maintain Financial Strength
ExxonMobil’s financial position remains unparalleled in our industry. In today’s challenging economic environment this represents a unique competitive advantage. Moody’s and Standard & Poor’s recognize our superior financial strength by assigning the highest credit rating to our financial obligations. ExxonMobil is one of very few public companies that has maintained this credit rating consistently for several decades.
Our financial strength is a competitive advantage and gives us the flexibility to pursue and finance attractive investment opportunities around the world across business cycles. Host governments and project partners recognize our unique capabilities and benefit from the financial strength and expertise we bring to the development of resources.

     
 

Geographic Diversity
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Strong Cash Flows(1)
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(1) Net cash from operating and investing activities, excluding changes in
restricted cash and cash equivalents, and marketable securities (see page 17).


 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW

Shareholder Information
ExxonMobil’s core objective is to deliver long-term growth in shareholder value. Over the past five years, we have distributed over $146 billion to our shareholders through quarterly dividend payments and share purchases to reduce shares outstanding. In 2008 our total shareholder distributions were $40 billion, including $32 billion of share purchases.
In 2008 ExxonMobil raised annual dividends to our shareholders to $1.55 per share, an increase of 13 percent versus the previous year. We have paid a dividend each year for more than a century and have increased annual dividends per share in each of the last 26 years.
ExxonMobil reduced the number of shares outstanding by 24 percent over the last five years through our flexible share purchase program. Reducing shares outstanding increases the percent ownership of the company that each remaining share represents, and contributes to increased earnings and cash flow per share.


 DIVIDEND AND SHAREHOLDER RETURN INFORMATION
                                         
    2008     2007     2006     2005     2004  
 
                                       
Net income per common share (dollars)
    8.78       7.36       6.68       5.76       3.91  
Net income per common share – assuming dilution (dollars)
    8.69       7.28       6.62       5.71       3.89  
         
Dividends per common share (dollars)
                                       
First quarter
    0.35       0.32       0.32       0.27       0.25  
Second quarter
    0.40       0.35       0.32       0.29       0.27  
Third quarter
    0.40       0.35       0.32       0.29       0.27  
Fourth quarter
    0.40       0.35       0.32       0.29       0.27  
         
Total
    1.55       1.37       1.28       1.14       1.06  
         
Dividends per share growth (annual percent)
    13.1       7.0       12.3       7.5       8.2  
         
Number of common shares outstanding (millions)
                                       
Average
    5,149       5,517       5,913       6,266       6,482  
Average – assuming dilution
    5,203       5,577       5,970       6,322       6,519  
Year end
    4,976       5,382       5,729       6,133       6,401  
         
Cash dividends paid on common stock (millions of dollars)
    8,058       7,621       7,628       7,185       6,896  
Cash dividends paid to net income (percent)
    18       19       19       20       27  
Cash dividends paid to cash flow(1) (percent)
    13       15       15       15       17  
         
Total return to shareholders (annual percent)
    (13.2 )     24.3       39.2       11.7       27.9  
         
Market quotations for common stock (dollars)
                                       
High
    96.12       95.27       79.00       65.96       52.05  
Low
    56.51       69.02       56.42       49.25       39.91  
Average daily close
    82.68       83.23       65.35       58.24       45.29  
Year-end close
    79.83       93.69       76.63       56.17       51.26  
         
(1) Net cash provided by operating activities.
 
Cumulative Distributions to Shareholders
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Increasing Ownership
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Safety, Health & Environment
We are committed to high standards of safety, security, health, and environmental care. We continue to deliver results that demonstrate that commitment.
2008 HIGHLIGHTS
  Workforce safety performance continues to lead industry
 
  Reduction in Upstream hydrocarbon flaring
 
  Over 60-percent reduction in total spills greater than one barrel from 2001
 
  Zero spills from company-operated marine vessels
 
  Reduction in greenhouse gas emissions
Guiding Principles
ExxonMobil is committed to maintaining high standards of safety, security, health, and environmental (SSH&E) care. We comply with all applicable laws and regulations, and where laws and regulations do not exist, we apply responsible standards. We know that operating responsibly wherever we do business makes ExxonMobil a better company. We strive to lower injuries, illnesses, and operational incidents with environmental impact to zero. We believe ExxonMobil’s commitment to achieving and sustaining superior performance in safety, health, and the environment is closely linked to outstanding performance in all other aspects of operations. Our unchanging priority is to manufacture essential commodities in a manner that preserves and protects health and safety, and which safeguards the environment.
Safety, security, health, and environmental risks are managed within a company-wide framework that we call OIMS – our Operations Integrity Management System. OIMS is a disciplined, structured, and global approach to managing these risks and is used in our businesses and facilities worldwide. ExxonMobil developed OIMS over 15 years ago, with several cycles of improvement. OIMS has been strengthened to include environmental business planning and safety for office workers. Lloyd’s Register Quality Assurance has recognized OIMS as meeting all requirements of the Occupational Health and Safety Assessment Series for health and safety management systems (OHSAS 18001:1999), in addition to the International Organization for Standardization’s specification for environmental management systems (ISO 14001:2004). The same rigor and discipline that underpin our investment program are also applied in our approach to the management of our performance in safety, security, health, and the environment.
Risk Management
We recognize that risks are inherent to our business, and we take a disciplined, systematic approach to reducing these risks. Business continuity planning and emergency preparedness are two elements that help address risk, and we place great emphasis on preparedness to ensure a quick and effective response to incidents. When hurricanes Gustav and Ike struck the U.S. Gulf Coast in 2008, our emergency response plans were executed effectively, facilitating the recovery of our operations. We are currently assessing our hurricane response plans to capture opportunities for improvement, consistent with our commitment to continuously improve our preparedness.


     
 

Industry-Leading Safety
Lost-Time Injuries and Illnesses
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(1) Employee safety data from participating American Petroleum Institute
companies (2008 industry data not available at time of publication).
ExxonMobil leads the industry with our low incident rates through effective management systems and a workforce that is committed to a culture of safe operations.
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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW

Safety and Health
At ExxonMobil, excellence in safety and health in the workplace is a core value. We lead the industry with our low incident rates for work-related injuries and illnesses. Based on careful analysis of incidents and risks, we continuously work to improve the safety and health of our employees and contractors. Since 2000 we have reduced our workforce lost-time incident rate by an average of over 12 percent per year. Our approach to safety and health management is yielding good results. But we will not be satisfied until we have achieved a work environment in which Nobody Gets Hurt.
To achieve this goal, effective safety, security, health, and environmental (SSH&E) leadership is essential. ExxonMobil recognizes that everyone in our workforce can be an SSH&E leader. We are incorporating advanced SSH&E leadership concepts into our management systems and training, as well as enhancing core career development tools and processes. Our objective is to develop and improve the leadership behaviors necessary to achieve SSH&E excellence.
Contractor safety is another area of continued focus. We have rigorous processes to identify, select, and qualify contractors. In recent years, a high percentage of contractor incidents involved workers who were new to the site, the company, or the industry. As a result, we have developed practices to help ensure these workers are effectively mentored and integrated into the workplace.
ExxonMobil continues to strengthen process safety through OIMS in the areas of risk management and facilities integrity assurance. In addition ExxonMobil has taken a leadership role in industry to update facility standards and to develop new standards for personnel fatigue management and process safety performance measurement.
ExxonMobil maintains an active commitment to public health in the communities in which we operate. We believe that self-sustaining improvements in public health are a key
     
 
Greenhouse Gas Reductions from ExxonMobil Actions from 2006 to 2008
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enabler for broader economic and social gains. For example in Papua New Guinea, public health reporting systems are limited, so understanding the full scope of disease is a particular challenge. In response we have conducted health impact assessments and have launched disease prevalence surveys to determine the scope of disease our workforce may encounter.
ExxonMobil has a disciplined process to comply with product safety requirements in more than 180 countries where we have business interests. The core of this process is the use of globally consistent product safety warnings. We monitor and assess changing and emerging safety requirements to ensure our products continue to be safe for use by the public.
Environment
ExxonMobil is committed to achieving excellent environmental performance in each of our businesses to Protect Tomorrow. Today. Through strong environmental management, our businesses have made improvements in environmental performance. As an example, in 2008 ExxonMobil achieved zero spills from company-owned and long-term chartered marine vessels. It is our objective to operate responsibly everywhere we do business by implementing scientifically sound, practical solutions that consider the needs of the communities in which we operate. We maintain strong management processes through OIMS and adhere to all applicable laws and regulations. In addition our business lines are expected to:
  Deliver superior environmental performance, which will lead to competitive advantage.
 
  Continually improve performance and drive incidents with environmental impact to zero.
 
  Achieve industry leadership in key environmental performance areas.
ExxonMobil recognizes that rising greenhouse gas (GHG) emissions pose risks to society and ecosystems. We are committed to the development of technology to reduce GHG emissions. We were the founding sponsor of the Global Climate and Energy Project (GCEP) at Stanford University, a pioneering research effort to identify potentially “game-changing,” breakthrough science to reduce GHG emissions. ExxonMobil is also a world leader in carbon management technologies and has researched and developed carbon-handling technologies for more than 30 years. In addition to our internal research programs, ExxonMobil supports carbon capture and storage research at the International Energy Agency’s Greenhouse Gas Research & Development Program, the Massachusetts Institute of Technology, the Georgia Institute of Technology, the University of Texas, and Stanford University.
ExxonMobil has active programs to improve energy efficiency and to reduce flaring of natural gas in our


 


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operations. Steps taken in these programs since 2005 resulted in reductions in greenhouse gas emissions of more than 7 million tons in 2008, the equivalent of taking about 1.4 million cars off the roads in the United States. One primary strategy for energy efficiency improvement is investment in the efficient cogeneration of steam and electric power. ExxonMobil has interests in over 4.5 gigawatts of cogeneration capacity located in more than 30 locations worldwide.
We have numerous examples of incorporating this full life cycle concept in our projects around the world.
Our Corporate Environmental Aspects Guide enables comprehensive identification and risk-based assessment of environmental impacts. This guide supports steps one and two in the life cycle of our operations. It provides consistent guidance to our operating facilities and design groups to identify and manage environmental risks.

A Sustainable Approach to Environmental Protection
Understanding the full life cycle of our operations is important to operating in an environmentally sustainable manner. There are four key steps we take through the life cycle of our operations. The first step is to assess the surroundings before beginning development. The second step is to design and construct facilities to minimize our environmental footprint. The third is to ensure the integrity of the facilities we operate, and the fourth is to restore the environment when operations are concluded.
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Our Environmental Business Planning (EBP) process contained within OIMS is used by our businesses to update environmental targets and establish improvement plans. This process supports steps three and four as it helps the businesses integrate environmental improvement efforts, such as spill prevention, efficiency improvements, and emissions reductions into the routine operations of our businesses. Guided by our EBP process, we continue to take action to reduce emissions as well as to minimize our footprint in environmentally sensitive locations.


FULL LIFE CYCLE EXAMPLE: OIL SANDS AND HEAVY OIL
1 – Assess
Athabasca River – Oil Sands Development Slightly over 2 percent of the Athabasca River’s natural flow is estimated to be required to support existing and approved industry oil sands developments in northern Alberta, Canada. To help ensure that requirements on the river are efficiently managed, we have taken an active role in multistakeholder water planning processes. These processes are helping to build positive relationships with the local community and contributing to regional water solutions.
2 – Design
Kearl Oil Sands Project – Reducing Freshwater Consumption We look for opportunities to reduce freshwater consumption in the design phase of every new project. A key component of the Kearl project design is the use of water storage to enable reduced water withdrawal during low-flow winter periods.
3 – Operate
Cold Lake – Recycling During Operations Our Cold Lake operations have significantly reduced the water required to produce heavy oil. These deposits are too deeply buried for surface mining, so large amounts of steam are injected into the underground deposits. This softens the resource so it can be pumped to the surface. As a result of improvements since start-up, 98 percent of the water produced during recovery operations is recycled to make more steam.
4 – Restore
Kearl Oil Sands Project – Restoring Loss of Fish Habitat In 2008 we began building three lakes adjacent to Kearl Lake near the oil sands mining area to replace fish habitat that will be lost due to mining activities. One goal of the project is to achieve no net loss of the productive capacity of fish habitat. The first lake is expected to cost $20 million and be filled over the years 2009 to 2011.
     
 
At Cold Lake, high-pressure steam is injected into the ground to coax the oil to the surface.
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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
 FUNCTIONAL EARNINGS
                                                                         
    2008 Quarters                                
                                     
 
(millions of dollars)   First     Second     Third     Fourth     2008     2007     2006     2005     2004  
 
                                                                       
Net Income (U.S. GAAP)
                                                                       
Upstream
                                                                       
United States
    1,631       2,034       1,879       699       6,243       4,870       5,168       6,200       4,948  
Non-U.S.
    7,154       7,978       9,092       4,935       29,159       21,627       21,062       18,149       11,727  
Total
    8,785       10,012       10,971       5,634       35,402       26,497       26,230       24,349       16,675  
         
Downstream
                                                                       
United States
    398       293       978       (20 )     1,649       4,120       4,250       3,911       2,186  
Non-U.S.
    768       1,265       2,035       2,434       6,502       5,453       4,204       4,081       3,520  
Total
    1,166       1,558       3,013       2,414       8,151       9,573       8,454       7,992       5,706  
         
Chemical
                                                                       
United States
    284       102       257       81       724       1,181       1,360       1,186       1,020  
Non-U.S.
    744       585       830       74       2,233       3,382       3,022       2,757       2,408  
Total
    1,028       687       1,087       155       2,957       4,563       4,382       3,943       3,428  
         
Corporate and financing
    (89 )     (577 )     (241 )     (383 )     (1,290 )     (23 )     434       (154 )     (479 )
         
Net income (U.S. GAAP)
    10,890       11,680       14,830       7,820       45,220       40,610       39,500       36,130       25,330  
         
Net income per common share (dollars)(1)
    2.05       2.25       2.89       1.57       8.78       7.36       6.68       5.76       3.91  
Net income per common share –
assuming dilution
(dollars)(1)
    2.03       2.22       2.86       1.55       8.69       7.28       6.62       5.71       3.89  
         
 
                                                                       
Special Items
                                                                       
Upstream
                                                                       
United States
                                                     
Non-U.S.
                1,620             1,620                   1,620        
Total
                1,620             1,620                   1,620        
         
Downstream
                                                                       
United States
                                              (200 )     (550 )
Non-U.S.
                                              310        
Total
                                              110       (550 )
         
Chemical
                                                                       
United States
                                                     
Non-U.S.
                                              540        
Total
                                              540        
         
Corporate and financing
          (290 )     (170 )           (460 )           410              
         
Corporate total
          (290 )     1,450             1,160             410       2,270       (550 )
         
 
                                                                       
Earnings Excluding Special Items(2)
                                                                       
Upstream
                                                                       
United States
    1,631       2,034       1,879       699       6,243       4,870       5,168       6,200       4,948  
Non-U.S.
    7,154       7,978       7,472       4,935       27,539       21,627       21,062       16,529       11,727  
Total
    8,785       10,012       9,351       5,634       33,782       26,497       26,230       22,729       16,675  
         
Downstream
                                                                       
United States
    398       293       978       (20 )     1,649       4,120       4,250       4,111       2,736  
Non-U.S.
    768       1,265       2,035       2,434       6,502       5,453       4,204       3,771       3,520  
Total
    1,166       1,558       3,013       2,414       8,151       9,573       8,454       7,882       6,256  
         
Chemical
                                                                       
United States
    284       102       257       81       724       1,181       1,360       1,186       1,020  
Non-U.S.
    744       585       830       74       2,233       3,382       3,022       2,217       2,408  
Total
    1,028       687       1,087       155       2,957       4,563       4,382       3,403       3,428  
         
Corporate and financing
    (89 )     (287 )     (71 )     (383 )     (830 )     (23 )     24       (154 )     (479 )
         
Corporate total
    10,890       11,970       13,380       7,820       44,060       40,610       39,090       33,860       25,880  
         
Earnings per common share (dollars)(1)
    2.05       2.30       2.62       1.57       8.56       7.36       6.61       5.40       3.99  
         
Earnings per common share –
assuming dilution
(dollars)(1)
    2.03       2.27       2.59       1.55       8.47       7.28       6.55       5.35       3.97  
         
 
(1)   Computed using the average number of shares outstanding during each period. The sum of the four quarters may not add to the full year.
 
(2)   See Frequently Used Terms on pages 96 through 99.

 


Table of Contents

   
EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
11
RETURN ON AVERAGE CAPITAL EMPLOYED(1) BY BUSINESS
Return On Average
Capital Employed
(LINE GRAPH)
                                         
(percent)   2008     2007     2006     2005     2004  
 
                                       
Upstream
                                       
 
                                       
United States
    42.6       34.7       37.1       46.0       37.0  
 
                                       
Non-U.S.
    56.7       43.7       47.9       45.6       31.5  
 
                                       
Total
    53.6       41.7       45.3       45.7       32.9  
 
                                       
         
 
                                       
Downstream
                                       
 
                                       
United States
    23.7       65.1       65.8       58.8       28.6  
 
                                       
Non-U.S.
    34.8       28.7       24.5       22.6       18.0  
 
                                       
Total
    31.8       37.8       35.8       32.4       21.0  
 
                                       
         
 
                                       
Chemical
                                       
 
                                       
United States
    16.0       24.9       27.7       23.1       19.4  
 
                                       
Non-U.S.
    22.4       39.0       36.5       30.9       25.7  
 
                                       
Total
    20.4       34.0       33.2       28.0       23.5  
 
                                       
         
 
                                       
Corporate and financing
  NA     NA     NA     NA     NA  
 
                                       
         
 
                                       
Corporate total
    34.2       31.8       32.2       31.3       23.8  
 
                                       
         
(1)   Capital employed consists of shareholders’ equity and their share of consolidated debt, including ExxonMobil’s share of amounts applicable to equity companies. See Frequently Used Terms on pages 96 through 99.


AVERAGE CAPITAL EMPLOYED(1) BY BUSINESS
Average Capital Employed
(BAR GRAPH)
                                         
(millions of dollars)   2008     2007     2006     2005     2004  
 
                                       
Upstream
                                       
 
                                       
United States
    14,651       14,026       13,940       13,491       13,355  
 
                                       
Non-U.S.
    51,413       49,539       43,931       39,770       37,287  
 
                                       
Total
    66,064       63,565       57,871       53,261       50,642  
 
                                       
         
 
                                       
Downstream
                                       
 
                                       
United States
    6,963       6,331       6,456       6,650       7,632  
 
                                       
Non-U.S.
    18,664       18,983       17,172       18,030       19,541  
 
                                       
Total
    25,627       25,314       23,628       24,680       27,173  
 
                                       
       
 
                                       
Chemical
                                       
 
                                       
United States
    4,535       4,748       4,911       5,145       5,246  
 
                                       
Non-U.S.
    9,990       8,682       8,272       8,919       9,362  
 
                                       
Total
    14,525       13,430       13,183       14,064       14,608  
 
                                       
         
 
                                       
Corporate and financing
    23,467       26,451       27,891       24,956       14,916  
 
                                       
         
 
                                       
Corporate total
    129,683       128,760       122,573       116,961       107,339  
 
                                       
         
 
                                       
Average capital employed applicable to equity companies included above
    25,651       24,267       22,106       20,256       18,049  
 
                                       
         
(1)   Average capital employed is the average of beginning- and end-of-year business segment capital employed, including ExxonMobil’s share of amounts applicable to equity companies. See Frequently Used Terms on pages 96 through 99.



Table of Contents

   
12
EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
 CAPITAL AND EXPLORATION EXPENDITURES (1)
                                         
(millions of dollars)   2008     2007     2006     2005     2004  
 
Upstream
                                       
Exploration
                                       
United States
    734       415       425       297       248  
Non-U.S.
    2,137       1,494       1,619       1,396       1,035  
Total
    2,871       1,909       2,044       1,693       1,283  
         
Production(2)
                                       
United States
    2,600       1,792       2,058       1,841       1,669  
Non-U.S.
    14,011       11,913       12,059       10,844       8,629  
Total
    16,611       13,705       14,117       12,685       10,298  
         
Power and Coal
                                       
United States
          5       3       4       5  
Non-U.S.
    252       105       67       88       129  
Total
    252       110       70       92       134  
         
Total Upstream
    19,734       15,724       16,231       14,470       11,715  
         
 
                                       
Downstream
                                       
Refining
                                       
United States
    1,430       906       559       497       550  
Non-U.S.
    1,248       1,267       1,051       871       774  
Total
    2,678       2,173       1,610       1,368       1,324  
         
Marketing
                                       
United States
    176       201       233       217       201  
Non-U.S.
    638       876       852       859       811  
Total
    814       1,077       1,085       1,076       1,012  
         
Pipeline/Marine
                                       
United States
    30       21       32       39       24  
Non-U.S.
    7       32       2       12       45  
Total
    37       53       34       51       69  
       
Total Downstream
    3,529       3,303       2,729       2,495       2,405  
         
 
                                       
Chemical
                                       
United States
    441       360       280       243       262  
Non-U.S.
    2,378       1,422       476       411       428  
Total Chemical
    2,819       1,782       756       654       690  
           
 
Other
                                       
United States
    61       44       130       80       66  
Non-U.S.
                9             9  
Total other
    61       44       139       80       75  
         
Total capital and exploration expenditures
    26,143       20,853       19,855       17,699       14,885  
         
 
(1)   See Frequently Used Terms on pages 96 through 99.
 
(2)   Including related transportation.

 


Table of Contents

   
 EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW 
13
 TOTAL CAPITAL AND EXPLORATION EXPENDITURES BY GEOGRAPHY
                                         
(millions of dollars)   2008     2007     2006     2005     2004  
                                         
United States
    5,472       3,744       3,720       3,218       3,025  
Canada/Latin America
    1,926       1,522       1,862       1,940       1,867  
Europe
    3,727       4,042       3,721       2,829       2,845  
Africa
    5,422       3,639       4,019       3,815       3,330  
Asia Pacific/Middle East
    7,669       6,156       4,601       3,241       2,168  
Russia/Caspian
    1,927       1,750       1,932       2,656       1,650  
         
Total worldwide
    26,143       20,853       19,855       17,699       14,885  
         
 DISTRIBUTION OF CAPITAL AND EXPLORATION EXPENDITURES
                                         
(millions of dollars)   2008     2007     2006     2005     2004  
                                         
Consolidated Companies’ Expenditures
                                       
Capital expenditures
    19,841       15,242       15,361       13,792       11,901  
Exploration costs charged to expense
                                       
United States
    189       280       243       157       192  
Non-U.S.
    1,252       1,177       925       795       891  
Depreciation on support equipment(1)
    10       12       13       12       15  
Total exploration expenses
    1,451       1,469       1,181       964       1,098  
         
Total consolidated companies’ capital and exploration expenditures
                                       
(excluding Depreciation on support equipment)
    21,282       16,699       16,529       14,744       12,984  
 
ExxonMobil’s Share of Non-Consolidated Companies’ Expenditures
                                       
Capital expenditures
    4,845       4,122       3,315       2,938       1,865  
Exploration costs charged to expense
    16       32       11       17       36  
Total non-consolidated companies’ capital and exploration expenditures
    4,861       4,154       3,326       2,955       1,901  
         
Total capital and exploration expenditures
    26,143       20,853       19,855       17,699       14,885  
         
 
(1)   Not included as part of total capital and exploration expenditures, but included as part of exploration expenses, including dry holes, in the Summary Statement of Income, page 16.
     
 
     
Functional Capex Distribution
  Geographic Capex Distribution
 
   
(IMAGE)
  (IMAGE)

 


Table of Contents

   
14
EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
 NET INVESTMENT IN PROPERTY, PLANT AND EQUIPMENT AT YEAR END
                                         
(millions of dollars)   2008     2007     2006     2005     2004  
                                         
Upstream
                                       
United States
    17,920       16,714       16,467       16,222       16,410  
Non-U.S.
    55,493       56,810       51,943       46,595       45,603  
Total
    73,413       73,524       68,410       62,817       62,013  
         
Downstream
                                       
United States
    10,492       9,705       9,320       9,334       9,408  
Non-U.S.
    18,762       20,443       19,598       18,695       20,402  
Total
    29,254       30,148       28,918       28,029       29,810  
         
Chemical
                                       
United States
    4,396       4,448       4,553       4,685       4,887  
Non-U.S.
    7,034       5,623       4,766       4,619       5,162  
Total
    11,430       10,071       9,319       9,304       10,049  
         
Other
    7,249       7,126       7,040       6,860       6,767  
         
Total net investment
    121,346       120,869       113,687       107,010       108,639  
         
 DEPRECIATION AND DEPLETION EXPENSES
                                         
(millions of dollars)   2008     2007     2006     2005     2004  
                                         
Upstream
                                       
United States
    1,391       1,469       1,263       1,293       1,453  
Non-U.S.
    7,266       7,126       6,482       5,407       4,758  
Total
    8,657       8,595       7,745       6,700       6,211  
         
Downstream
                                       
United States
    656       639       632       615       618  
Non-U.S.
    1,672       1,662       1,605       1,611       1,646  
Total
    2,328       2,301       2,237       2,226       2,264  
         
Chemical
                                       
United States
    410       405       427       416       408  
Non-U.S.
    422       418       473       410       400  
Total
    832       823       900       826       808  
         
Other
    562       531       534       501       484  
         
Total depreciation and depletion expenses
    12,379       12,250       11,416       10,253       9,767  
         
 OPERATING COSTS (1)
                                         
(millions of dollars)   2008     2007     2006     2005     2004  
                                         
Production and manufacturing expenses
    37,905       31,885       29,528       26,819       23,225  
Selling, general, and administrative
    15,873       14,890       14,273       14,402       13,849  
Depreciation and depletion
    12,379       12,250       11,416       10,253       9,767  
Exploration
    1,451       1,469       1,181       964       1,098  
         
Subtotal
    67,608       60,494       56,398       52,438       47,939  
ExxonMobil’s share of equity company expenses
    7,204       5,619       4,947       4,520       4,209  
         
Total operating costs
    74,812       66,113       61,345       56,958       52,148  
         
 
(1)   See Frequently Used Terms on pages 96 through 99.

 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
15
 SUMMARY BALANCE SHEET AT YEAR END
                                         
(millions of dollars)   2008     2007     2006     2005     2004  
                                         
Assets
                                       
Current assets
                                       
Cash and cash equivalents
    31,437       33,981       28,244       28,671       18,531  
Cash and cash equivalents – restricted
                4,604       4,604       4,604  
Marketable securities
    570       519                    
Notes and accounts receivable, less estimated doubtful amounts
    24,702       36,450       28,942       27,484       25,359  
Inventories
                                       
Crude oil, products and merchandise
    9,331       8,863       8,979       7,852       8,136  
Materials and supplies
    2,315       2,226       1,735       1,469       1,351  
Other current assets
    3,911       3,924       3,273       3,262       2,396  
         
Total current assets
    72,266       85,963       75,777       73,342       60,377  
         
Investments, advances, and long-term receivables
    28,556       28,194       23,237       20,592       18,404  
Property, plant and equipment, at cost, less accumulated depreciation and depletion
    121,346       120,869       113,687       107,010       108,639  
Other assets, including intangibles, net
    5,884       7,056       6,314       7,391       7,836  
         
Total assets
    228,052       242,082       219,015       208,335       195,256  
         
 
                                       
Liabilities
                                       
Current liabilities
                                       
Notes and loans payable
    2,400       2,383       1,702       1,771       3,280  
Accounts payable and accrued liabilities
    36,643       45,275       39,082       36,120       31,763  
Income taxes payable
    10,057       10,654       8,033       8,416       7,938  
         
Total current liabilities
    49,100       58,312       48,817       46,307       42,981  
         
Long-term debt
    7,025       7,183       6,645       6,220       5,013  
Postretirement benefits reserves
    20,729       13,278       13,931       10,220       10,850  
Deferred income tax liabilities
    19,726       22,899       20,851       20,878       21,092  
Other long-term obligations
    13,949       14,366       11,123       9,997       9,612  
Equity of minority interests
    4,558       4,282       3,804       3,527       3,952  
         
Total liabilities
    115,087       120,320       105,171       97,149       93,500  
         
                                         
Commitments and contingencies(1)
                                       
 
                                       
Shareholders’ Equity
                                       
Common stock without par value
    5,314       4,933       4,786       4,477       4,053  
Earnings reinvested
    265,680       228,518       195,207       163,335       134,390  
Accumulated other comprehensive income
                                       
Cumulative foreign exchange translation adjustment
    1,146       7,972       3,733       979       3,598  
Postretirement benefits reserves adjustment
    (11,077 )     (5,983 )     (6,495 )            
Minimum pension liability adjustment
                      (2,258 )     (2,499 )
Unrealized gains/(losses) on stock investments
                            428  
Common stock held in treasury
    (148,098 )     (113,678 )     (83,387 )     (55,347 )     (38,214 )
         
Total shareholders’ equity
    112,965       121,762       113,844       111,186       101,756  
         
Total liabilities and shareholders’ equity
    228,052       242,082       219,015       208,335       195,256  
         
 
(1)   For more information, please refer to Appendix A, Note 15 of ExxonMobil’s 2009 Proxy Statement.
 
The information in the Summary Statement of Income (for 2006 to 2008), the Summary Balance Sheet (for 2007 and 2008), and the Summary Statement of Cash Flows (for 2006 to 2008), shown on pages 15 through 17, corresponds to the information in the Consolidated Statement of Income, Consolidated Balance Sheet, and the Consolidated Statement of Cash Flows in the financial statements of ExxonMobil’s 2009 Proxy Statement. For complete consolidated financial statements, including notes, please refer to Appendix A of ExxonMobil’s 2009 Proxy Statement. See also Management’s Discussion and Analysis of Financial Condition and Results of Operations and other information in Appendix A of the 2009 Proxy Statement.

 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
 SUMMARY STATEMENT OF INCOME
                                         
(millions of dollars)   2008     2007     2006     2005     2004  
 
                                       
Revenues and Other Income
                                       
Sales and other operating revenue(1)(2)
    459,579       390,328       365,467       358,955       291,252  
Income from equity affiliates
    11,081       8,901       6,985       7,583       4,961  
Other income(3)
    6,699       5,323       5,183       4,142       1,822  
         
Total revenues and other income
    477,359       404,552       377,635       370,680       298,035  
         
 
                                       
Costs and Other Deductions
                                       
Crude oil and product purchases
    249,454       199,498       182,546       185,219       139,224  
Production and manufacturing expenses
    37,905       31,885       29,528       26,819       23,225  
Selling, general and administrative expenses
    15,873       14,890       14,273       14,402       13,849  
Depreciation and depletion
    12,379       12,250       11,416       10,253       9,767  
Exploration expenses, including dry holes
    1,451       1,469       1,181       964       1,098  
Interest expense
    673       400       654       496       638  
Sales-based taxes(1)
    34,508       31,728       30,381       30,742       27,263  
Other taxes and duties
    41,719       40,953       39,203       41,554       40,954  
Income applicable to minority interests
    1,647       1,005       1,051       799       776  
         
Total costs and other deductions
    395,609       334,078       310,233       311,248       256,794  
         
Income before income taxes
    81,750       70,474       67,402       59,432       41,241  
Income taxes
    36,530       29,864       27,902       23,302       15,911  
         
Net income
    45,220       40,610       39,500       36,130       25,330  
         
 
                                       
Net Income per Common Share (dollars)
    8.78       7.36       6.68       5.76       3.91  
 
                                       
Net Income per Common Share – Assuming Dilution (dollars)
    8.69       7.28       6.62       5.71       3.89  
         
 
(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)   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 Summary Statement of Income (for 2006 to 2008), the Summary Balance Sheet (for 2007 and 2008), and the Summary Statement of Cash Flows (for 2006 to 2008), shown on pages 15 through 17, corresponds to the information in the Consolidated Statement of Income, Consolidated Balance Sheet, and the Consolidated Statement of Cash Flows in the financial statements of ExxonMobil’s 2009 Proxy Statement. For complete consolidated financial statements, including notes, please refer to Appendix A of ExxonMobil’s 2009 Proxy Statement. See also Management’s Discussion and Analysis of Financial Condition and Results of Operations and other information in Appendix A of the 2009 Proxy Statement.

 


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 SUMMARY STATEMENT OF CASH FLOWS
                                         
(millions of dollars)   2008     2007     2006     2005     2004  
 
                                       
Cash Flows from Operating Activities
                                       
Net income
                                       
Accruing to ExxonMobil shareholders
    45,220       40,610       39,500       36,130       25,330  
Accruing to minority interests
    1,647       1,005       1,051       799       776  
Adjustments for noncash transactions
                                       
Depreciation and depletion
    12,379       12,250       11,416       10,253       9,767  
Deferred income tax charges/(credits)
    1,399       124       1,717       (429 )     (1,134 )
Postretirement benefits expense in excess of/ (less than) payments
    57       (1,314 )     (1,787 )     254       886  
Other long-term obligation provisions in excess of/(less than) payments
    (63 )     1,065       (666 )     398       806  
Dividends received greater than/(less than) equity in current earnings of equity companies
    921       (714 )     (579 )     (734 )     (1,643 )
Changes in operational working capital, excluding cash and debt
Reduction/(increase) – Notes and accounts receivable
    8,641       (5,441 )     (181 )     (3,700 )     (472 )
– Inventories
    (1,285 )     72       (1,057 )     (434 )     (223 )
– Other current assets
    (509 )     280       (385 )     (7 )     11  
Increase/(reduction)  – Accounts and other payables
    (5,415 )     6,228       1,160       7,806       6,333  
Net (gain) on asset sales
    (3,757 )     (2,217 )     (1,531 )     (1,980 )     (268 )
All other items – net
    490       54       628       (218 )     382  
         
Net cash provided by operating activities
    59,725       52,002       49,286       48,138       40,551  
         
 
                                       
Cash Flows from Investing Activities
                                       
Additions to property, plant and equipment
    (19,318 )     (15,387 )     (15,462 )     (13,839 )     (11,986 )
Sales of subsidiaries, investments, and property, plant and equipment
    5,985       4,204       3,080       6,036       2,754  
Decrease/(increase) in restricted cash and cash equivalents
          4,604                   (4,604 )
Additional investments and advances
    (2,495 )     (3,038 )     (2,604 )     (2,810 )     (2,287 )
Collection of advances
    574       391       756       343       1,213  
Additions to marketable securities
    (2,113 )     (646 )                  
Sales of marketable securities
    1,868       144                    
         
Net cash used in investing activities
    (15,499 )     (9,728 )     (14,230 )     (10,270 )     (14,910 )
         
 
                                       
Cash Flows from Financing Activities
                                       
Additions to long-term debt
    79       592       318       195       470  
Reductions in long-term debt
    (192 )     (209 )     (33 )     (81 )     (562 )
Additions to short-term debt
    1,067       1,211       334       377       450  
Reductions in short-term debt
    (1,624 )     (809 )     (451 )     (687 )     (2,243 )
Additions/(reductions) in debt with three months or less maturity
    143       (187 )     (95 )     (1,306 )     (66 )
Cash dividends to ExxonMobil shareholders
    (8,058 )     (7,621 )     (7,628 )     (7,185 )     (6,896 )
Cash dividends to minority interests
    (375 )     (289 )     (239 )     (293 )     (215 )
Changes in minority interests and sales/(purchases) of affiliate stock
    (419 )     (659 )     (493 )     (681 )     (215 )
Tax benefits related to stock-based awards
    333       369       462              
Common stock acquired
    (35,734 )     (31,822 )     (29,558 )     (18,221 )     (9,951 )
Common stock sold
    753       1,079       1,173       941       960  
         
Net cash used in financing activities
    (44,027 )     (38,345 )     (36,210 )     (26,941 )     (18,268 )
         
Effects of exchange rate changes on cash
    (2,743 )     1,808       727       (787 )     532  
         
Increase/(decrease) in cash and cash equivalents
    (2,544 )     5,737       (427 )     10,140       7,905  
Cash and cash equivalents at beginning of year
    33,981       28,244       28,671       18,531       10,626  
         
Cash and cash equivalents at end of year
    31,437       33,981       28,244       28,671       18,531  
         
 
The information in the Summary Statement of Income (for 2006 to 2008), the Summary Balance Sheet (for 2007 and 2008), and the Summary Statement of Cash Flows (for 2006 to 2008), shown on pages 15 through 17, corresponds to the information in the Consolidated Statement of Income, Consolidated Balance Sheet, and the Consolidated Statement of Cash Flows in the financial statements of ExxonMobil’s 2009 Proxy Statement. For complete consolidated financial statements, including notes, please refer to Appendix A of ExxonMobil’s 2009 Proxy Statement. See also Management’s Discussion and Analysis of Financial Condition and Results of Operations and other information in Appendix A of the 2009 Proxy Statement.

 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW

The Outlook for Energy –
A View to 2030
Energy – in all its forms – is critical to economic growth, development, and social welfare. Meeting the projected increase in energy demand to support growing populations and expanding economies poses many challenges, and will require an integrated set of solutions.
To help us prepare for the future energy marketplace, each year ExxonMobil develops The Outlook for Energy, a broad in-depth look at the long-term global trends for energy demand and supply, and their impact on carbon dioxide (CO2) emissions. The results of this comprehensive study provide a foundation for ExxonMobil’s business planning and are shared publicly to help build understanding of the world’s energy needs and challenges.
The Link Between Economic Growth and Energy
Energy and economic growth have long been entwined: The availability of energy supports long-term economic and social progress; economic growth drives increased energy usage.
So projecting future energy demand requires estimating economic growth and prosperity. Despite current economic conditions, global economic output, as measured by Gross Domestic Product (GDP), is expected to increase by close to 3 percent annually on average through 2030.
Importantly the global economy is becoming more energy efficient. From 1980 to 2005, “energy intensity” – the amount of energy used per unit of economic output – improved by 1 percent per year on average. Going forward to 2030, we expect the rate of improvement will be 70 percent faster than in the past.
Even with significant energy intensity gains, global energy demand is expected to increase 1.2 percent per year on average through 2030. The majority of new energy demand
will come from fast-growing economies and rising personal prosperity in the Asia Pacific region. Oil, natural gas, and coal will remain the primary energy sources through 2030, but renewable sources like wind, solar, and biofuels will grow at a rapid rate.
Transportation Demand Driven by Developing Economies
Transportation provides perhaps the most visible use of energy. Moving people and goods across cities, across countries, and around the world requires tremendous amounts of energy, and that will not change in the foreseeable future. In fact, energy demand for transportation – which includes cars, trucks, ships, trains, and planes – is expected to increase by 40 percent from 2005 to 2030, and represent about 20 percent of worldwide energy demand.

In the United States, total transportation fuel demand will plateau around 2015 and decline thereafter. Commercial demand will rise due to increased economic activity but will be more than offset by a significant decline in light-duty vehicle demand reflecting increasing vehicle fuel economy over time. By 2030 total demand will fall about 10 percent from its peak.
The transportation demand outlook for the European Union is fairly similar, with light-duty fuel demand expected to decline as increasingly efficient vehicles enter the market. Commercial-related demand – representing a greater share than in the United States – will continue to grow and offset declining light-duty vehicle demand. Total demand will be relatively flat through 2030.
In contrast China’s light-duty vehicle fleet will grow significantly to over 100 million vehicles by 2030, up from 12 million in 2005, reflecting rising GDP and increasing prosperity. China’s overall transportation fuel demand, including heavy-duty vehicles and other commercial segments, will more than triple by 2030, growing at nearly 5 percent per year and approaching the transportation demand level in the European Union.


 
Worldwide Economics and Energy
()

 


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Transportation Demand by Region and Sector
()
 

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.
Electricity Demand Increases Need for Power Generation
Electricity is something many take for granted, yet around 1.5 billion people still do not have access to reliable electricity supplies. As economies grow and access increases, global demand for electricity is projected to increase 75 percent by 2030 versus 2005.
Consistent with this projection, power generation will remain the largest and fastest growing segment of global demand, increasing to 40 percent of total demand by 2030. This is driven in large part by strong growth in Asia Pacific. China, for example, will experience demand growth of more than 100 percent, while demand in the United States and European Union will grow only modestly.
Meeting the expected worldwide growth in power demand will require a diverse set of energy sources. Today coal is dominant, meeting about 45 percent of global power generation demand, followed by natural gas and nuclear. Coal will retain the largest share; however, natural gas, nuclear, and renewables will all gain market share.
The mix of energy sources will vary across the globe. In the United States and European Union, coal will lose market share primarily to natural gas and nuclear power. In China however, coal will continue to be the dominant power generation fuel source due to its low cost and ample supply.
Our estimates of demand for particular energy types in the United States and other developed countries assume that a “cost of carbon” will be adopted in some manner over the next two decades. While actual costs will depend on specific regulations, the implication of such a policy approach would be to increase the cost to produce


 
Power Generation by Region
()

 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW

electricity using coal or, to a lesser extent, natural gas – and as a result substantially affect the relative economics of electricity supply options.
Growing Worldwide Liquids Demand
Liquid fuels such as oil, condensates, and natural gas liquids provide the largest share of energy supply today, due to their affordability, wide availability, and ease of transport. By 2030 global demand for liquids is expected to grow to approximately 108 million oil-equivalent barrels per day or close to 30 percent more than in 2005.
This liquids demand projection has important implications for potential sources of supply. Non-OPEC crude and condensate production is expected to remain relatively flat through 2030. Canadian oil sands should reach about 4 million oil-equivalent barrels per day by 2030, while natural gas liquids, OPEC condensate and other liquids will also grow, reflecting, in part, increases in natural gas production. Biofuels will also grow significantly, reaching almost 3 million oil-equivalent barrels per day by 2030.
These projected supply levels leave a gap between expected supply and demand that represents the amount of crude oil production needed from OPEC countries. In 2030, the “call on OPEC” is likely to be approximately 38 million oil-equivalent barrels per day.
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.
LNG Import Market Will Grow
Increases in natural gas demand in major markets will require new sources of supply, primarily from imports. North American production will remain steady due to production of unconventional resources, such as tight gas and shale gas. However, demand growth of 1 percent per year will mean that imports must increase dramatically by 2030 to keep pace, essentially all via liquefied natural gas (LNG). Europe, with falling domestic production, will also need to meet its growing demand with imports from pipelines and LNG. Asia Pacific demand will grow 150 percent by 2030 and will be met partly by imports from pipelines and LNG.
The need for additional natural gas imports will have a dramatic impact on the worldwide LNG market. By 2030, LNG trade worldwide will more than triple versus 2005.
Global Energy in Perspective
When viewed globally, it is clear that the world’s energy mix is highly diverse. Today, oil, natural gas, and coal provide approximately 80 percent of world energy. By 2030, oil will remain the largest source of energy supply at close to 35 percent. Natural gas will grow the fastest of the fossil fuels and will overtake coal as the second-largest energy source. Nuclear power will increase significantly, surpassing coal in terms of absolute growth and becoming the fourth-largest fuel source. Hydro and geothermal will also grow, but they are limited by the availability of natural sites. Wind, solar, and biofuels will increase rapidly at about 9 percent per year on average, the highest growth rate of all fuels.


 
     
 
   
Liquids Supply and Demand
  Gas Supply and Demand Balance
 
   
()

OPEC —Organization of the Petroleum Exporting Countries
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Growth in Global Energy Demand
  Energy-Related CO2 Outlook by Region
 
   
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In developing this Outlook, we assume significant efficiency improvements over time. Compared to 2005 energy-intensity levels, these improvements translate to energy savings of approximately 170 million oil-equivalent barrels per day by 2030 – about double the corresponding growth in demand. Achieving these gains will be critical to helping meet our global energy challenges.
Growing Energy Demand and CO2 Emissions
The outlook for energy-related CO2 emissions is linked directly to projections of the amount and type of energy required globally. In the United States and European Union, CO2 emissions will likely decline about 15 percent by 2030 due to generally flat demand – reflecting increased efficiencies – and a less carbon-intensive energy mix overall.
China, however, is facing significant increases in CO2. We expect its CO2 emissions to rise 70 percent by 2030, reflecting growing energy demand as well as the prominent and increasing use of coal. By 2030, China’s CO2 emissions will be comparable to the combined emissions of the United States and Europe and represent 25 percent of the world’s CO2 emissions.
Looking globally we do not expect CO2 emissions to peak by 2030. While the United States and other developed countries will be reducing emissions, the economic growth and associated energy needs of developing countries will drive global CO2 levels higher.
This highlights the challenge ahead for the world – how to continue to provide the energy necessary to bring billions of people up the economic ladder while mitigating the growth of CO2 emissions.
Conclusion
We draw several key conclusions from our Outlook for Energy:
  Growing populations and expanding economies will drive global energy demand approximately 35 percent higher from 2005 to 2030 – even with substantial gains in energy efficiency.
 
  Oil, natural gas, and coal will continue to provide the majority of the world’s energy needs, meeting close to 80 percent of global demand through 2030 – due to their abundance, affordability, and availability. Nuclear energy will grow as emphasis on low-carbon fuels increases. Renewable fuels will also grow rapidly.
 
  Reducing global energy-related CO2 emissions growth will be difficult given the energy needs of developing countries.
 
This Outlook makes clear that the world’s energy challenges are formidable. We believe that meeting these global energy challenges requires an integrated set of solutions that includes:
 
  Moderating demand through new technologies that improve energy efficiency in our vehicles, homes, and businesses.
 
  Expanding access to all economically viable energy sources – oil, natural gas, coal, nuclear, and alternative and renewable sources such as wind, solar, and biofuels.
 
  Mitigating the risks of climate change through technologies that advance energy efficiency, enable widespread use of renewables, and capture and store CO2 emissions.
Looking to 2030 and beyond, we realize that the scale of our global challenge is enormous, but so, too, is our commitment to succeed and our capacity to innovate. ExxonMobil is confident that by pursuing this integrated set of solutions – while working with governments to create reliable policy and investment environments for these solutions to thrive – the world can achieve both energy and environmental security to support growing economic prosperity.


 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
Technology
ExxonMobil effectively develops and globally deploys proprietary technology. Our research efforts encompass all of our functional businesses: Upstream, Downstream, and Chemical.
UPSTREAM TECHNOLOGY
ExxonMobil is committed to investing in a broad range of proprietary technologies that provide a competitive advantage in exploration, field development, hydrocarbon recovery, and production operations. Applications of these technologies result in reduced exploration risks, improved well performance, greater hydrocarbon recovery, lower costs, and safer operations.

     
Enhanced Basin Modeling
ExxonMobil uses advanced computer modeling to help identify the most promising exploration areas within a hydrocarbon basin. This technology provides valuable insight into the location, quantity, and timing of hydrocarbon formation and movement through the subsurface. New capabilities have been added to the proprietary basin modeling software Stellar, integrating a broader spectrum of subsurface data to improve analytical predictions. As a result, ExxonMobil researchers are able to evaluate various scenarios of hydrocarbon accumulation to identify the areas with the greatest probability of hydrocarbon occurrence. This capability has proven effective in supporting decisions that range in scope from capturing new exploration acreage to positioning new wells.
  (PICTURE)
A Stellar model of the subsurface shows the likelihood of
encountering hydrocarbons.
 
 
     
(PICTURE)
ExxonMobil geologists study outcrops to improve the
understanding of deepwater reservoir systems.
  Effective Deepwater Reservoir Modeling
Many of the hydrocarbon resources currently under development by ExxonMobil are in reservoirs deposited in deepwater environments. Deepwater reservoirs typically have a complex sedimentary structure that can make reservoir management challenging. To improve deepwater reservoir management, ExxonMobil researchers have developed novel analytical tools and an industry-leading, integrated evaluation process. The new approach incorporates reservoir modeling, outcrop interpretation of reservoir analogs, experimental sediment studies, and seismic prediction of reservoir quality. ExxonMobil has used this technology in deepwater fields in West Africa to increase hydrocarbon recovery, and plans to apply it globally.
 
 
     
Unique Depositional Modeling
Seismic data typically cannot define all of the features affecting the performance of a subsurface reservoir. To improve reservoir characterization, ExxonMobil has developed unique capabilities to simulate mathematically the sediment erosion, transport, and deposition processes that act together to form a reservoir. Results from this process-based simulation enable researchers to create numerical reservoir models with more detailed sedimentary structures and rock properties than seismic data alone can provide. This information provides a superior understanding of the reservoir to improve resource recovery.
  (PICTURE)
Results of a process-based simulation of a channel deposited in deep
water show the channel topography and geometries.


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Advanced Reservoir Characterization Technologies
Accurate characterization of reservoir fluid and rock properties is essential to understanding and improving reservoir performance. ExxonMobil technologies provide unmatched capabilities in this area to underpin global investment decisions.
ExxonMobil researchers utilize state-of-the-art geochemical laboratories in all phases of upstream projects to ensure the optimal development of resources. During the exploration phase, analyses of geochemical data help predict the location and quality of untapped oil accumulations. During development, analyses of oil composition provide information about connectivity between reservoirs, assisting in the optimal placement of wells. During the production phase, additional analyses help optimize the recovery of reservoir fluids and ensure operational integrity. These applications have been enhanced by the recent addition of a multidimensional chromatograph that provides unparalleled precision in oil analysis.
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Multidimensional chromatography provides high-resolution analysis of oil composition.
 
ExxonMobil’s laboratories allow researchers to accurately characterize subsurface rock properties by recreating the temperature, pressure, stress, and fluid conditions found within the reservoir. Capabilities include pioneering technology for whole-core measurements of highly heterogeneous formations such as carbonate rocks found in the Middle East. ExxonMobil has also developed leading technologies for measuring the properties of gas-condensate reservoirs and unconventional gas resources, such as those of the Piceance Basin in Colorado. By providing key reservoir property data, these capabilities have helped improve development and depletion planning and have increased resource recovery.
ExxonMobil has developed a state-of-the-art laboratory for measuring geomechanical rock properties on core samples under reservoir conditions. Knowledge of subsurface mechanical properties is important in various applications: drilling deviated wells in highly layered rock such as shale, understanding fractures in unconventional reservoirs, and determining the effect of directional permeability on productivity in horizontal wells. Such applications are critical in the development of unconventional gas resources such as tight gas and shale gas, and can lead to more successful wells.
 
Above: Whole-core technology provides scale-appropriate reservoir property characterization for heterogeneous reservoirs.
Below: ExxonMobil’s state-of-the-art geomechanics laboratory enables directional permeability measurements on rock samples.


 


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ExxonMobil’s large-scale laboratory apparatus can recreate geologic and reservoir conditions to test new bitumen recovery methods.
 
Economical Recovery
from Thin Bitumen Reservoirs

ExxonMobil is actively researching new approaches for hydrocarbon recovery from bitumen, also referred to as heavy oil, that exists in reservoirs too thin to be produced economically with current technology. These innovative recovery approaches have the potential to extract the bitumen without the use of either steam or heat and to recover a far higher percentage of bitumen than is currently possible. By minimizing the use of steam and heat, these new methods could significantly reduce energy use and carbon dioxide (CO2) emissions. Laboratory tests and numerical modeling have yielded encouraging results for the future application of these technologies.
 
 
Optimal Well Performance
Improving individual well performance is an important component in maximizing the value of hydrocarbon resources. Modern high- production wells routinely produce fluids from multiple zones measuring thousands of feet long, increasing the importance of optimal well design. ExxonMobil has developed a new process for evaluating various well-completion designs to predict which design will be the most productive. This process extends traditional reservoir simulation and takes into account the dynamics of fluid flow in the completion interval and near-well region. The resulting predictions lead to completion designs that ensure maximum production throughout the life of the well. This technology has been used in Middle East carbonate wells to reduce completion times and increase production rates, and broader deployment is planned.
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Advanced modeling capabilities allow ExxonMobil to optimize well performance.
 
 
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A model of an arctic drillship is being tested under varying ice thicknesses, ice drift speeds, and vessel directions.
 
Specialized Arctic Technology
The U.S. Geological Survey estimates that more than one-fifth of the world’s undiscovered recoverable hydrocarbon resources are in the Arctic, and more than 80 percent of those resources are offshore. Because current technology limits offshore arctic operations to the open-water season, which may last just weeks, drilling a well typically requires multiple seasons. To extend the drilling season, ExxonMobil scientists and engineers are developing drillship technology that equips ships with special reinforced hulls and advanced propulsion systems for arctic environments. These innovations will allow wells to be completed in fewer seasons. Efforts are under way to apply this technology in the exploration of the Canadian Beaufort Sea.

 


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Robust Pipeline Design
The commercial development of remote oil and gas resources often requires pipeline construction in very challenging environments. Through a suite of advanced pipeline technologies, ExxonMobil has addressed the technical issues of fabricating pipelines that ensure operational integrity in these environments. These technologies include new laboratory methods for quantifying the effect of complex loads, physics-based computational models for predicting load response, and techniques for welding and materials-joining. Using these technologies, large pipelines can be constructed that are able to withstand ground deformation from earthquakes as well as pressure exerted from arctic soil and ice movements. ExxonMobil’s advanced pipeline technologies are being applied in projects worldwide.
  (GRAPHIC)
ExxonMobil’s advanced pipeline technologies are underpinned by computational models and validated by rigorous experiments.
 
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Enhanced Drilling Design
Equipment vibration during drilling, especially for extended-reach wells, leads to significant energy loss and can damage drilling equipment. In response ExxonMobil has developed an industry-leading design process for reducing drilling vibrations. This process includes the unique capability to make design upgrades in real time at the well site. Field trials of this process have demonstrated increased drilling equipment life and significantly higher rates of penetration, thereby reducing drilling costs. As an extension of ExxonMobil’s proven Fast Drill Process, the new technology is yielding positive results in worldwide drilling operations, including those in Russia, the United States, and offshore Canada.
ExxonMobil’s new design process
enhances drilling performance by
reducing equipment vibrations.
 
 
 
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Innovative Flow Assurance
One of the challenges of producing hydrocarbons in extreme environments such as ultra-deep water and the Arctic is the formation of hydrates, solids that can clog production flow lines. ExxonMobil is developing an innovative, reliable solution to avoid the formation of hydrate blockages without the need for costly chemicals or insulation. The method uses static mixers that create water droplets to enhance the production of small hydrate particles. The small particles are able to move freely without clumping or sticking to pipe walls, assuring unrestricted flow. Pilot laboratory studies have proven the concept, and field tests of the technology are planned.

ExxonMobil’s pilot-scale hydrate flow loop enables development and evaluation of new flow-assurance technologies in a controlled environment.
 
 

 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
DOWNSTREAM TECHNOLOGY
ExxonMobil’s Downstream technology programs are focused in three broad areas: advantaged feeds, higher-value products, and lower-cost processes. Our long-term commitment to developing and deploying proprietary technology continues to deliver competitive advantage.

Catalysis
ExxonMobil is a leader in the discovery, development, and deployment of advantaged catalyst technology. Catalysts accelerate the rate of desired chemical reactions and are used in over 85 percent of ExxonMobil’s refinery conversion units. We continue to build upon our history of leadership in delivering novel catalyst technologies that add value to our business. Utilizing state-of-the-art experimentation and modeling tools, we are enhancing our ability to rapidly discover and commercialize new catalysts. These new catalysts allow efficient upgrading of feeds, such as high-sulfur heavy crudes, into cleaner finished products.
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ExxonMobil scientists use a state-of-the-art visualization facility to review results from advanced modeling of hydroprocessing catalysts.
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Two RCPSA units were successfully commercialized in one of our European refineries.
 
Rapid Cycle Pressure Swing Adsorption
Hydrogen is a key component used in refineries to manufacture cleaner fuels. Efficient management of hydrogen molecules within a refinery is becoming increasingly important to meet more stringent sulfur specifications in fuel products. ExxonMobil recently commercialized new rapid cycle pressure swing adsorption (RCPSA) technology to recover hydrogen from fuels process units. The simplicity and compactness of this skid-mounted technology will enable new opportunities to expand process unit capacity by recovering hydrogen from product gas streams that otherwise would be burned in the refinery fuel gas system. The new RCPSA technology, which was jointly developed with QuestAir Technologies, can cost up to 50 percent less than conventional PSA technology, depending on the scale and type of application. ExxonMobil is currently pursuing additional hydrogen recovery opportunities in refineries and chemical plants.
 
Unconventional Energy Resources
ExxonMobil is actively working on a variety of unconventional fuel technologies including gasification, methanol to gasoline, and biofuels.

Gasification • ExxonMobil entered into an agreement with Pratt & Whitney Rocketdyne to develop advanced gasification technology to convert coal, coke, or biomass into synthesis gas. Synthesis gas can be converted into chemical products or transportation fuels, or used as fuel for power generation. This technology could also facilitate the use of carbon capture and storage to reduce greenhouse gas emissions from processing carbon rich feedstocks such as coal and coke.
  Methanol to Gasoline • ExxonMobil’s Methanol to Gasoline (MTG) technology efficiently converts methanol into high-quality gasoline. When coupled with commercially proven gasification and methanol synthesis technology, MTG is an effective way to produce premium transportation fuel from coal. We recently began licensing this technology and have several signed licensees.

Biofuels • ExxonMobil continues to evaluate a number of short- and longer-term biofuel options and opportunities. As an example, we have developed a proprietary test method to fingerprint biodiesel mixtures. This unique methodology will allow us to improve the efficiency and reliability of our blending operations, while continuing to meet product quality specifications.

 


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Heat Exchanger Fouling Mitigation
Refinery heat exchanger networks are designed to efficiently transfer heat from hot process streams to cold feed streams, thereby minimizing process heat input requirements. The performance of this equipment is an important part of overall site energy usage. Corrosion and fouling in heat exchangers can impair performance by creating a thermal-insulating deposit that reduces the heat exchange efficiency between the hot and cold fluids. These effects are particularly detrimental in exchangers that operate under high-temperature conditions.
   
ExxonMobil researchers have discovered that formation of a unique surface on the metal tubes of a heat exchanger can significantly reduce corrosion and fouling. Heat exchangers with these characteristics are being evaluated at two Gulf Coast refineries and additional exchangers will be tested at two other ExxonMobil refineries in 2009. When deployed, the technology will reduce furnace firing and associated CO2 emissions.

An engineer inspects a modified heat exchanger tube bundle prior to installation at a U.S. Gulf Coast refinery.
   
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Advanced Modeling
ExxonMobil is using advanced computational fluid dynamics (CFD) modeling to enhance the performance and utilization of existing refinery assets. For example, detailed CFD analysis of our proprietary Fluid Coking process led to a new hardware design that better utilizes existing reactor volume. The new configuration increases the yield of gasoline and distillate products and improves energy efficiency.
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Computational Fluid Dynamics modeling enables evaluation of time-varying behavior of multiphase refinery processes.
   
Supply Chain Optimization
ExxonMobil operates one of the world’s largest and most complex supply chains. The company’s business experts and engineers work constantly to improve its effectiveness and reduce costs. We are actively developing and deploying unique supply chain optimization technologies that place us at the forefront of industry. One example is our METEORITE supply chain program that aids in the scheduling, transportation, and optimization of our feedstock shipments around the world.
   

 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
CHEMICAL TECHNOLOGY
Development and deployment of industry-leading process and product technology provides a competitive advantage for ExxonMobil. Within our chemical technology portfolio, we manage a pipeline of projects that are fully aligned with our strategic business initiatives, including lower-cost processes, advantaged feeds, and premium product development.

Lower-Cost Processes
We have a number of programs targeting more efficient, lower-cost processes as we continually strive to lower operating costs at our chemical manufacturing facilities by delivering improved efficiency, greater reliability, and increased asset utilization.

Technology activities include breakthrough developments such as our new butyl rubber polymerization process, as well as incremental improvements from implementation of many smaller, focused efficiency initiatives. These developments are enabled by sophisticated computer process simulations, advanced materials engineering, proprietary equipment design, and novel product and catalyst chemistry.
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ExxonMobil Chemical has received American Chemistry Council energy efficiency awards for 11 consecutive years as a result of continued implementation of technology best practices.
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Advantaged Feeds
Many of our technology programs are focused on developing innovative ways to allow processing of lower-cost feeds. Through proprietary design of processing equipment, we have increased the flexibility of our units to handle a wide variety of hydrocarbon feed streams. In addition we have developed complex computational tools, including integrated real-time optimization programs, which allow us to rapidly change feeds into our chemical plants and refineries to maximize the value of all molecules.

These technology best practices are also incorporated into new equipment design. For example the new ethylene steam cracker currently under construction in Singapore has been designed to have the greatest feed flexibility of any ExxonMobil steam cracker in the world.

Our steam cracker technology is a competitive advantage. New furnaces are larger and more efficient than those typically used in industry. We have also qualified more than 300 new feeds over the past four years, increasing flexibility to use the most-advantaged feeds.
Premium Product Development
We continue to develop premium products across our chemical portfolio. Breakthroughs in metallocene catalyst technology have given us the ability to create whole new families of higher-value chemical products from commodity chemical building blocks. For example:

Enable metallocene polyethylene produces strong and clear films that can reduce packaging weight by up to 20 percent versus typical films, delivering energy savings throughout the supply chain in uses from packaging to greenhouse coverings.
  ()
Use of high-throughput experimentation (HTE) catalyst screening has allowed us to accelerate design and commercialization of next- generation products from metallocene catalysts.
Vistamaxx specialty elastomers have high elasticity, softness, toughness, and adhesion properties. This unique combination of attributes is useful in a wide range of products from medical garments to packaging materials to diapers.
We also continue to expand the applications for metallocene technology to other product families including polypropylene, adhesive polymers, specialty elastomers, and others.

 


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Integration – A Continuing Competitive Advantage
ExxonMobil is able to capture new opportunities and grow shareholder value through the integration of our businesses. Integration between business functions is a competitive advantage that delivers value through the identification of attractive investment opportunities, implementation of best practices, application of advantaged technology, and optimization of our operations.

OPPORTUNITY IDENTIFICATION
ExxonMobil maintains a unique position in the industry due to the size and scale of our technological and operational capabilities in each of our Upstream, Downstream, and Chemical businesses. We have a consistent track record of identifying and executing world-class, integrated projects that generate increased value to our shareholders and to resource owners. We maximize our competitive advantage by leveraging economies of scale, proprietary technology, unrivaled project and operations management, and optimization of raw materials. For example in 2009, ExxonMobil and our project partners expect to start up the only fully integrated refining, petrochemical, and fuels marketing venture with foreign participation in China.
ADVANTAGED TECHNOLOGY
Advantaged technology continues to be one of the keys to unlocking value in our operations, projects, resources, and products. By taking an integrated approach to the development and deployment of new technology, we are able to concentrate our research efforts in the highest-value areas, driven by our business needs. We accomplish this by maintaining a dialogue between our researchers, scientists, engineers, and operating functions to identify key business challenges that require technical solutions. This technology advantage is enhanced further by ExxonMobil’s ability to rapidly deploy technological breakthroughs through our global functional organization.


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IMPLEMENTATION OF BEST PRACTICES
Integration across all of ExxonMobil’s business operations – Upstream, Downstream, and Chemical – allows us to capture benefits by sharing best practices. Using centralized support services as well as common systems and processes, we are able to leverage the expertise of our employees around the world. For example our credit and cash management activities are managed using global processes and risk tolerances ensuring a consistent approach to managing risk. Similarly we have a single capital project management system for all of our businesses that takes advantage of our time-tested and consistent best practices: optimized concept selection, comprehensive project planning, disciplined project execution, and reappraisal of project performance.
OPERATIONAL OPTIMIZATION
We optimize operations across our functional businesses by sharing best practices as well as utilizing proprietary technologies. For example in our refineries and chemical plants, we use integrated process models that enable feedstocks to be specifically tailored to maximize their value. Our Molecule Management technology includes advanced molecular fingerprinting and modeling tools that enable us to process the optimal mix of crudes and maximize the yield of higher-value products and feedstocks. Similarly sophisticated process control technologies optimize unit performance, increase reliability, and reduce operating costs. Maximizing the value of every molecule is just one of the many benefits of optimizing operations.


 


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Upstream
Exploration, Development, Production, and Gas & Power Marketing
UPSTREAM STRATEGIES
ExxonMobil’s fundamental Upstream strategies guide our global exploration, development, production, and gas and power marketing activities:
  Identify and pursue all attractive exploration opportunities
 
  Invest in projects that deliver superior returns
 
  Maximize profitability of existing oil and gas production
 
  Capitalize 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. ExxonMobil’s ability to integrate and execute these strategies consistently delivers superior long-term value.
 
Qatargas II Train 4 will be the first of four 7.8-million-tons-per-year liquefaction facilities to be commissioned in 2009. These facilities will be the largest in the world with 50 percent more capacity than any existing liquefaction facility.
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2008 Results and Highlights

Industry-leading workforce safety performance.
Earnings were a record $35.4 billion.
Upstream return on average capital employed was 54 percent, and has averaged 44 percent over the past five years.
Earnings per oil-equivalent barrel were $24.67, exceeding those of our competitors.
Total liquids production and natural gas production available for sale was 3.9 million oil-equivalent barrels per day, the highest among our competitors.
Replaced 103 percent of production with proved oil and gas reserve additions of 1.5 billion oil-equivalent barrels, including asset sales and excluding year-end price/cost effects.
Upstream Return on Average Capital Employed
()
 
(1) Royal Dutch Shell, BP, and Chevron values are estimated on a consistent basis with ExxonMobil, based on public information.


Resource base additions totaled 2.2 billion oil-equivalent barrels. ExxonMobil’s resource base now stands at 72 billion oil-equivalent barrels.
Finding and resource-acquisition costs were $1.32 per oil-equivalent barrel.
Upstream capital and exploration spending was $19.7 billion, driven by an active exploration program, selective investment in a strong portfolio of development projects, and continued investment to enhance the value of existing assets.
 
UPSTREAM COMPETITIVE ADVANTAGES

Portfolio Quality • The quality, size, and diversity of ExxonMobil’s resource base and project inventory underpin a strong long-term outlook.
Global Integration • The global functional Upstream companies work with the Downstream and Chemical businesses to identify and deliver integrated solutions that maximize resource value.
Discipline and Consistency • We explore, develop, produce, and market using globally deployed management systems that ensure consistent application of the highest technical, operational, and commercial standards.
Value Maximization • From optimum development concept selection continuing through mid- and late-life investments to increase reservoir recovery, ExxonMobil maximizes resource value over the life of each asset.
Long-Term Perspective • Consistent, selective capital investment and focused technology development ensure robust investments over the long term.


                                         
UPSTREAM STATISTICAL RECAP   2008     2007     2006     2005     2004  
Earnings (millions of dollars)
    35,402       26,497       26,230       24,349       16,675  
Liquids production (thousands of barrels per day)
    2,405       2,616       2,681       2,523       2,571  
Natural gas production available for sale (millions of cubic feet per day)
    9,095       9,384       9,334       9,251       9,864  
Oil-equivalent production (thousands of barrels per day)
    3,921       4,180       4,237       4,065       4,215  
Proved reserves replacement(1)(2) (percent)
    110       132       129       129       125  
Resource additions(2) (millions of oil-equivalent barrels)
    2,230       2,010       4,270       4,365       2,940  
Average capital employed(2) (millions of dollars)
    66,064       63,565       57,871       53,261       50,642  
Return on average capital employed(2) (percent)
    53.6       41.7       45.3       45.7       32.9  
Capital and exploration expenditures(2) (millions of dollars)
    19,734       15,724       16,231       14,470       11,715  
 
(1)   Excluding asset sales, the 2007 Venezuela expropriation, and year-end price/cost effects.
 
(2)   See Frequently Used Terms on pages 96 through 99.

 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW

Identify and Pursue All Attractive Exploration Opportunities
ExxonMobil’s exploration strategy is to identify, evaluate, pursue, and capture the highest quality opportunities around the world. Our global organization explores in diverse geological and geographical environments, covering the full range of resource life cycle and type including:
  New exploration plays and concepts that typically have high uncertainty but large potential to provide significant long-term resource growth.
 
  Unconventional resources such as tight gas, shale gas, heavy oil, and oil sands that can provide profitable, long-plateau production.
 
  Further exploration of established hydrocarbon provinces and mature plays that provide near-term resource additions and production.
 
  Discovered fields that are undeveloped or partially developed.
ExxonMobil’s disciplined, systematic exploration process consistently delivers an industry-leading portfolio of highly prospective opportunities that promote long-term resource additions and production growth. Our global reach and approach ensure a broad exposure to high-quality opportunities – from conventional by-the-bit exploration to opportunities that require close integration between the Upstream, Downstream, and Chemical businesses. The combination of world-class technical expertise and an extensive global exploration database provides a distinct competitive advantage in the identification, evaluation, pursuit, and capture of new opportunities.
We use our unique geoscience capabilities and understanding of the global hydrocarbon endowment to identify and prioritize all quality resources. Once identified, opportunities are assessed and screened for technical and economic viability, as well as materiality, on a globally
(GRAPHICS)
Seismic acquisition activities commenced in 2008 at ExxonMobil’s Arctic exploration play, offshore west Greenland.
 
Exploration Acreage Position by Region
(GRAPHICS)
 
consistent basis. Only the most robust opportunities are selected for further evaluation and investment.
Our systematic approach to exploration has resulted in the successful capture of numerous new, high-potential resource addition opportunities each year. These opportunities include conventional and unconventional resource types in new, untested areas as well as established ones. In 2008 ExxonMobil successfully captured new opportunities in eight different countries.
At year-end 2008, ExxonMobil’s net exploration acreage totaled 73 million acres in 33 countries. Since 2004 ExxonMobil’s exploration acreage position has increased by approximately 18 percent. This strong acreage position provides a high-quality, geographically and geologically diverse portfolio of opportunities to underpin future resource additions and production growth.


 

Resource Additions/Acquisitions by Geographic Region
(percent, oil-equivalent barrels added, 2004-2008)
(GRAPHICS)
Resource Additions/Acquisitions by Resource Type
(percent, oil-equivalent barrels added, 2004-2008)
(GRAPHICS)


 


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2008 KEY EXPLORATION CAPTURES
Canada ExxonMobil Canada and majority-owned affiliate Imperial Oil Limited were jointly awarded approximately 76,000 net acres in the Horn River Basin shale gas play, in northeast British Columbia. Including acreage captured in 2007, ExxonMobil’s total net acreage position is 152,000 acres.
Hungary ExxonMobil acquired 184,300 acres (ExxonMobil interest, 33.5 percent) in the Mako Trough in southeast Hungary. ExxonMobil will acquire a 50-percent interest in an additional 386,800 acres upon completion of a work program that includes drilling, well testing, and reservoir evaluation.
Indonesia ExxonMobil was awarded operatorship of the Gunting Block (ExxonMobil interest, 100 percent) located onshore and offshore East Java. The block comprises 406,500 acres.
Ireland ExxonMobil was awarded two exploration licenses in the Porcupine Basin of the Irish Sea. The licenses are located in water depths exceeding 6500 feet, and together comprise an area totaling 778,700 acres. ExxonMobil operates these licenses with an 80-percent interest.
Libya ExxonMobil was awarded operatorship of Contract Area 21 (ExxonMobil interest, 100 percent). The contract area comprises 2.5 million acres and is 110 miles offshore in water depths ranging from approximately 5400 feet to 8700 feet.
Nigeria ExxonMobil successfully concluded an agreement to acquire equity in Oil Prospecting License 223 (ExxonMobil interest, 27 percent). The license covers an area of 229,000 acres in the deep water offshore Nigeria.
Romania ExxonMobil signed an agreement to participate in the exploration of the Neptun Block (ExxonMobil interest, 50 percent) in the Black Sea offshore Romania. The agreement covers an area of approximately 1.8 million acres.
U.S. Onshore ExxonMobil expanded its position in the Piceance Basin, Colorado, by acquiring an additional 17,500 acres (ExxonMobil interest, 35 percent).
ExxonMobil was awarded six leases totaling 19,400 acres (ExxonMobil interest, 100 percent) in the Pennsylvania State Forest Lease Sale in 2008. These leases are part of the Marcellus shale gas play.
U.S. Gulf of Mexico ExxonMobil was awarded 128 blocks in the Gulf of Mexico Western Sale 207 and 14 blocks in the Gulf of Mexico Central Sale 206. ExxonMobil also received equity (ExxonMobil interest, 50 percent) in central Gulf of Mexico blocks WR540 and WR583 through the creation of the ExxonMobil-operated Julia Unit.


 
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Invest in Projects that Deliver Superior Returns
ExxonMobil continues to focus on disciplined investment decisions and industry-leading project execution to deliver superior returns from Upstream projects.
As project scale and complexity increase across the industry, the challenge to bring new energy supplies to market on time and within budget is growing. ExxonMobil’s project management systems leverage global best practices from previous projects to provide a disciplined and consistent approach to the diverse execution challenges around the world.
Superior project execution begins with selecting the design and operating concept that will be robust through a range of uncertainties and that will deliver maximum value over the life of the asset. It requires a commitment to and investment in technology to develop innovative solutions that lower costs, increase reliability, and deliver profitable volumes. ExxonMobil spends a great deal of time on execution planning to minimize cost and schedule risks during the execution phase of major projects.
The combination of global processes, proprietary technology, and project management expertise results in industry-leading project execution performance.
ExxonMobil has a large portfolio of project opportunities that is both global and diverse. Many of these developments are located in challenging environments and include deepwater, heavy oil/oil sands, unconventional gas, arctic, liquefied natural gas (LNG), and acid/sour gas projects. With a portfolio of more than 120 projects expected to develop over 24 billion oil-equivalent barrels (net), ExxonMobil selectively funds those projects that deliver robust financial performance and maximize profitable volumes growth over a wide range of economic conditions.
Project Execution Performance
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ExxonMobil development teams use a combination of global processes, proprietary technology, and project management expertise to deliver industry-leading project execution performance.


 
Diverse Project Portfolio
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Maximize Profitability of Existing
Oil and Gas Production
ExxonMobil applies the most cost-effective technology and operations management systems to all assets to maximize the commercial recovery of hydrocarbons.
ExxonMobil leverages its global functional organization to manage oil and gas assets through rapid technology transfer and best practices application. Our organizational structure and consistent processes enable the company to define priorities on a worldwide basis and to deploy resources when and where they are needed, drawing on an experienced, dedicated, and diverse workforce of exceptional quality.
We place significant focus on managing and optimizing base performance and continuously generating opportunities to maximize the value of our assets. High-quality reservoir management and rigorous depletion planning ensure optimum long-term field performance and enhance production from existing wells. We continually invest in our asset base to enhance resource recovery, maximize profitability, and extend field life. New production volumes are generated through drilling new wells, workovers, and implementing secondary or tertiary recovery programs.
ExxonMobil is recognized as an industry leader in the application of cost-effective technologies for enhanced oil recovery. These include using water or gas injection, heavy oil steamflooding, and sour gas injection techniques to increase reservoir recovery.
Production is maximized through a disciplined focus on operational integrity and by leveraging global best practices to improve facility reliability. For instance, maintenance activities are rigorously planned and executed resulting in optimized schedules and higher uptime.
All of these activities are performed with a structured focus on cost management and capital discipline in combination with a steadfast commitment to operational excellence. Operations integrity is fundamental to our success and is a top priority. Within the Operations Integrity Management System (OIMS), integrity management processes address all aspects of the business and define the global standards for safe and environmentally sound operations.
The asset base is continuously under review to ensure that every asset is contributing to our strategic objectives to the maximum extent possible. ExxonMobil consistently delivers higher earnings per barrel than our competitors. This is a direct reflection of our commitment to investment discipline, superior execution, and ability to maximize resource recovery.
Upstream Earnings per Barrel
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(1) Royal Dutch Shell, BP, and Chevron values calculated on a consistent basis with ExxonMobil, based on public information.
Production Volumes Added Through Work Programs
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Average Uptime Performance
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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW

Capitalize on Growing
Natural Gas and Power Markets
Reliable economic supplies of natural gas and power are fundamental to the world’s economic growth. ExxonMobil leverages its network of commercial experts and knowledge of global energy markets to capture the full value of growing gas and power markets.
We sell about 11 billion cubic feet of gas a day to a diverse customer base, from marketers and distributors to end consumers such as large power plants and industrial users. We also manage about 1 million barrels per day of natural gas liquids, generate a significant amount of power, and are a leading marketer of helium.
In North America, ExxonMobil is a major gas producer and processor with production from the Gulf of Mexico, the onshore Gulf Coast, the mid-continent of the United States, western Canada, and offshore eastern Canada. We continue development activities to increase production from our significant tight gas resources in the Piceance Basin in Colorado. In Canada, ExxonMobil acquired acreage in the Horn River shale gas play and has begun exploratory drilling. ExxonMobil also has a leading position in arctic gas resources in the Mackenzie Delta region of northern Canada and on the North Slope of Alaska.
Liquefied natural gas (LNG) will play an increasing role in our activities in the United States. The Golden Pass LNG regasification terminal in Texas is scheduled to start up in 2010, and we continue to seek regulatory approvals for a new LNG terminal offshore New Jersey.
In addition ExxonMobil is one of the world’s leading producers of helium through our Shute Creek gas processing plant in Wyoming.
In Europe, ExxonMobil is a leading gas producer through ownership in many key assets in the Netherlands, Germany, and the North Sea. LNG will also play an increasing role in our European supply portfolio. The first LNG cargo is expected to be received in early 2009 at the newly constructed South Hook LNG terminal in Wales. We are also completing construction of the Adriatic LNG terminal offshore Italy, which is expected to receive its first cargo in 2009.
In addition ExxonMobil is exploring several unconventional gas opportunities in Europe to help meet the region’s future demand for new supplies.
In Asia Pacific, ExxonMobil remains among the largest suppliers of gas in Australia and Malaysia, and also sells gas in Thailand, far east Russia, and Qatar. Our LNG ventures in Indonesia and Qatar provide significant volumes of gas to key European and Asian markets, including Japan, South Korea, Taiwan, and India.
Power Activities
ExxonMobil has interests in about 16,000 megawatts of power generation capacity worldwide. This includes a majority interest in the Castle Peak Power Company that generates electricity for consumers in Hong Kong and mainland China. ExxonMobil is an industry leader in the application of cogeneration technology with interests in more than 4500 megawatts of capacity used primarily to efficiently supply our own power and steam demands.
Integrated Approach
A major strength of ExxonMobil is the ability to combine our Upstream, Downstream, and Chemical businesses to create integrated solutions. This, together with our presence in all major supply and demand regions, provides us with a competitive advantage and positions us strongly to help meet the world’s growing natural gas and power demands.


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LNG MARKET
Liquefied natural gas (LNG) is expected to play an
increasing role in meeting the world’s energy
demand. Global LNG demand is projected to grow
about 4 percent per year through 2030, approaching 500 million tons per year or 15 percent of the world’s gas demand.
The expansion of global LNG infrastructure has enabled local gas markets to balance seasonal demands. ExxonMobil LNG ventures have the ability to sell into both liquid and non-liquid markets to maximize the value of our natural gas resources.
ExxonMobil is currently participating in LNG production in Qatar and Indonesia with a combined gross capacity of approximately 35 million tons per year, supplying markets in Asia, Europe, and North America. In Qatar, the world’s four largest LNG trains are expected to start up in 2009 with commissioning of the first train nearing completion in early 2009. Total gross capacity from these trains will be over 30 million tons of LNG per year. In 2008 ExxonMobil together with Qatar Petroleum added 20 vessels to their LNG shipping fleet.
In Asia Pacific, ExxonMobil is progressing the development of the Gorgon Jansz and PNG LNG projects. In addition we are pursuing new LNG project opportunities in Australia and West Africa.
Once these opportunities are brought on stream, ExxonMobil expects to be participating in gross LNG capacity of approximately 100 million tons per year, with significant volumes being placed in the growing markets of North America, Europe, and Asia Pacific.
ExxonMobil is also participating with Qatar Petroleum and others in LNG regasification terminal projects. In North America we are progressing construction of
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the Golden Pass LNG terminal in Texas, which is expected to be operational in 2010. ExxonMobil is also seeking regulatory approvals to build a floating LNG receiving terminal, BlueOcean Energy, 20 miles off the coast of New Jersey. This terminal is expected to start up during the middle of the next decade.
In Europe, the South Hook LNG terminal in the United Kingdom is expected to receive its first cargo in early 2009. Construction of the Adriatic LNG terminal offshore Italy is nearing completion and is expected to receive its first cargo in 2009.
ExxonMobil also participates in the Shimizu terminal in Japan, and together with Qatar Petroleum, holds capacity in the Fluxys terminal in Zeebrugge, Belgium.
Our large portfolio, coupled with our global presence, allows us to capture the highest-value market opportunities while helping to meet the world’s growing LNG demand.


 
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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW

National Content
Through the life cycle of all of our projects around the world, we see it as our responsibility to help develop sustainable human, social, and economic capacity in a way that benefits the people, communities, and the economic vitality of the host nations over the long term. In the Upstream, we call this “National Content.”
ExxonMobil has been engaged in building National Content for decades by focusing on workforce and supplier development in conjunction with strategic community investments.
Workforce Development
ExxonMobil pursues development of a diverse and highly talented workforce. Our workforce development strategy has two core objectives: recruit and develop nationals to manage and operate the local business; and, develop a talent pool capable of meeting our future global business needs.
Workforce development is based on a set of common principles utilized by ExxonMobil affiliates around the world. We apply global experiences, best practices, operational excellence, and innovative technology to help develop our local workforce. For example, when Malaysian production operations began in 1978, less than 50 percent of the approximately 300 employees were nationals. Thirty years later, nationals comprise 95 percent of the 655 employees. The company also has 110 Malaysians who are strongly contributing to ExxonMobil’s Upstream business in other locations worldwide.
Supplier Development
We are also committed to working with host governments to develop local companies to form a competitive industrial base and promote the purchase of local goods and services in our projects.
 
Workforce Development in Malaysia
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(GRAPHICS)
Supplier development efforts in Angola have resulted in sustained growth in local capacity and expertise.
 
In Angola for instance, local capacity was enhanced through business development and expenditures on local goods and services that increased from $500 million on the Kizomba A project, which started up in 2005, to $1.5 billion for the Kizomba C project, which started up in 2008. In addition ExxonMobil in collaboration with host governments and suppliers achieved the following “firsts”:
  Local fabrication of the high-strength steel turret components for the Kizomba C project – the first of their kind in Angola.
 
  Approximately $220 million of the East Area Natural Gas Liquids (NGL) II project was financed by Nigerian banks – the first for oil and gas ventures in Nigeria.
 
  Conducted subsea systems integration test in Nigeria for the deepwater Erha project – the first ever in West Africa.
Strategic Community Investments
ExxonMobil also has a long tradition of economic and social development by working with interested parties to identify and fund initiatives that reduce barriers to development and build capacity such as health, education, and infrastructure programs.
Key investments and initiatives in this area include:
Russia • Invested more than $120 million in Sakhalin infrastructure improvements, including health care, transportation, and utilities.
Qatar • Working with the Qatar Foundation and others to establish the Qatar Science and Technology Park – a world-class center for educational and scientific development.
Papua New Guinea • Developing a National Content plan to grow the capacity and capabilities of communities through specific health, education, infrastructure, and agriculture projects.


 


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Major Development Projects
ExxonMobil participated in eight major project start-ups in 2008 with nine more anticipated in 2009. Beyond 2009 an additional 44 major projects are in various stages of project planning, design, and execution. The portfolio contains about 120 projects including minor projects.
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Kizomba C The Kizomba C development (ExxonMobil interest, 40 percent) in Angola Block 15 includes two projects, Mondo and Saxi/Batuque. With two floating production, storage, and offloading (FPSO) vessels and 36 subsea wells, it is the largest subsea development operated by ExxonMobil worldwide. The projects exemplify ExxonMobil’s “design one, build multiple” strategy by constructing and commissioning two similar FPSO vessels. Together these projects are expected to recover approximately 600 million barrels of oil (gross) and produce 200 thousand barrels of oil per day at peak (gross).
Mondo The Mondo project began production on January 1, 2008, after the FPSO vessel and subsea production facilities were completed and commissioned in record time of 23 months from project approval to first oil.
Saxi/Batuque The Saxi/Batuque project began production on July 1, 2008, as scheduled, completing phase two of the staged development for Kizomba C.
 
The Saxi/Batuque FPSO, one of two similarly designed vessels for the Kizomba C development, exemplifies ExxonMobil’s “design one, build multiple” strategy.


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW

Jerneh B Natural gas production began in April 2008 from the offshore Jerneh B platform (ExxonMobil interest, 100 percent) in Malaysia. The platform was fully designed and constructed in Malaysia. At its peak, this development is expected to produce 150 million cubic feet per day (gross), bringing total production for the Jerneh field to 500 million cubic feet per day (gross).
Starling In the North Sea offshore the United Kingdom, production from the Starling gas condensate field (ExxonMobil interest, 72 percent) began in January 2008. The development consists of up to three wells tied back to the Shearwater platform over 20 miles away, and is expected to recover almost 40 million oil-equivalent barrels (gross).
Volve The Volve project offshore Norway began production in February 2008 (ExxonMobil interest, 30 percent) as an eight-well development. The project is expected to recover nearly 70 million oil-equivalent barrels with a gross production capacity of 50 thousand barrels per day of liquids and 30 million cubic feet per day of gas.
ACG Phase 3 The Azeri-Chirag-Gunashli (ACG) Phase 3 project (ExxonMobil interest, 8 percent), which developed the Deep Water Gunashli field offshore Azerbaijan, started production in April 2008. Production is expected to increase as additional wells are brought online and is projected to ultimately reach approximately 300 thousand barrels of oil per day (gross).
Thunder Horse The Thunder Horse project (ExxonMobil interest, 25 percent) in the central Gulf of Mexico began production in 2008, through a semisubmersible platform, located about 150 miles southeast of New Orleans, Louisiana, in just over 6000 feet of water. The facility is designed for peak production of 250 thousand barrels of oil and 200 million cubic feet of gas per day (gross).
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The Jerneh B platform, designed and constructed in Malaysia, began natural gas production in April 2008.
 
East Area NGL II The East Area natural gas liquids (NGL) II project (ExxonMobil interest, 51 percent) in Nigeria began production in March 2008. The project is expected to recover about 300 million barrels (gross) of natural gas liquids from associated gas produced from the East Area fields. At its peak, the project is expected to produce about 50 thousand barrels of natural gas liquids per day (gross). The project is part of an integrated plan to significantly reduce flaring and improve oil recovery in conjunction with the existing East Area Additional Oil Recovery project that started up in 2006.


 
The offshore facilities (left) of the East Area NGL II project extract natural gas liquids for further processing and export from the onshore Bonny River terminal (right).
     
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  MAJOR PROJECT START-UPS
                         
        Target Peak            
        Production (Gross)   ExxonMobil        
        Liquids   Gas   Working        
        (KBD)   (MCFD)   Interest (%)        
 
2008 (Actual)
                   
Angola
  Kizomba C Mondo   100     40     <  
 
  Kizomba C Saxi/Batuque   100     40     <  
Azerbaijan
  ACG Phase 3   300     8     =  
Malaysia
  Jerneh B     150   100     <  
Nigeria
  East Area NGL II   50     51     <  
Norway
  Volve   50   30   30     =  
U.K.
  Starling   15   160   72     =  
U.S.
  Thunder Horse   250   200   25     =  
2009 (Projected)
                   
Italy
  Adriatic LNG Terminal       45     5  
Norway
  Tyrihans   80   335   12     =  
Qatar
  Al Khaleej Gas Phase 2   70   1250   80*     <  
 
  Qatargas II Train 4**   80   1250   30     5  
 
  Qatargas II Train 5   80   1250   18     5  
 
  RasGas Train 6   75   1250   30     5  
 
  RasGas Train 7   75   1250   30     5  
U.K.
  South Hook LNG Terminal       24     5  
U.S.
  Piceance Phase 1   2   200   100     <  
2010-2011 (Projected)
                   
Angola
  Kizomba Satellites   125     40     <  
 
  Pazflor   200     20     =  
Australia
  Kipper/Tuna   15   175   40     <  
 
  Turrum   20   200   50     <  
Canada
  Hibernia Southern Extension   65     28     <  
Nigeria
  Etim/Asasa Pressure   50     40     <  
 
  Maintenance                    
Russia
  Sakhalin-1 Odoptu   35     30     <  
U.S.
  Golden Pass LNG Terminal       18     5  
 
  Prudhoe Bay Western Region   50     36     =  
2012+ (Projected)
                   
Angola
  Cravo-Lirio-Orquidea-Violeta   160     20     =  
 
  AB32 Southeast Hub   210     15     =  
 
  Palas-Astrea-Juno   150     25     =  
 
  Plutao-Saturno-Venus-Marte   150     25     =  
                                 
        Target Peak                    
        Production (Gross)   ExxonMobil                
        Liquids   Gas   Working                
        (KBD)   (MCFD)   Interest (%)                
         
2012+ (continued)                            
Australia
  Gorgon Jansz   15   2250   25     =          
 
  Scarborough     1190   50     <          
Canada
  Cold Lake Expansion   35     100     <          
 
  Cold Lake LASER Expansion   20     100     <          
 
  Hebron   140     36     <          
 
  Kearl Phase 1   110     100     <          
 
  Kearl Future Phases   200     100     <          
 
  Mackenzie Gas Project   10   830   56     <          
 
  Syncrude Aurora South   180     25     5          
 
  Phase 1 & 2                            
Indonesia
  Banyu Urip   165     45     <          
 
  Natuna     1100   76     <          
Italy
  Tempa Rossa   50   5   25     =          
Kazakhstan
  Kashagan Phase 1   360     17     =          
 
  Kashagan Future Phases   1190     17     =          
 
  Tengiz Expansion   370     25     =          
Nigeria
  Bonga North   100   60   20     =          
 
  Bonga Southwest   140   105   16     =          
 
  Bosi   135     56     <          
 
  Erha North Phase 2   45     56     <          
 
  LNG IPP Upstream     700   40     <          
 
  Satellite Field Development   125     40     <          
 
  Usan   180     30     =          
 
  Usari Pressure Maintenance   50     40     <          
Norway
  Trestakk   55   50   33     =          
Papua New
  PNG LNG   40   940   33     <          
Guinea
                               
Qatar
  Barzan   100   1500   10*     5          
Russia
  Sakhalin-1 Arkutun-Dagi   90     30     <          
 
  Sakhalin-1 Future Phases     800   30     <          
U.K.
  Fram   5   105   72     =          
U.S.
  Alaska Gas/Point Thomson   70   4500   36     *          
 
  Piceance Future Phases   10   780   100     <          


                     
< = ExxonMobil Operated   5 = Joint Operation = = Co-Venturer Operated            
 
* Pending Final Agreements   ** Offshore production started up in 2008.    – Not Applicable            
 

Major Project Start-Ups
Production by Start-Up Year
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Production by Type
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RESOURCES
ExxonMobil’s resource base totals 72 billion oil-equivalent barrels, of which 31 percent is proved. The size, diversity, and quality of our resource base is world class, and is a competitive advantage of the Corporation.
In 2008 ExxonMobil added 2.2 billion oil-equivalent barrels to the resource base, with significant additions resulting from drilling programs in the U.S. Gulf of Mexico, western Canada, onshore the United States, and West Africa. Overall the resource base increased by 0.3 billion oil-equivalent barrels in 2008 after accounting for revisions to existing fields, production, and asset sales.
ExxonMobil’s resource base is the largest among our competitors, and is highly diverse in terms of resource type and geography. The success of ExxonMobil’s global opportunity identification strategy is demonstrated by the addition of 3.2 billion oil-equivalent barrels of resource per year over the past five years.
The resource base is updated annually for new discoveries and resource additions, and to reflect changes in the estimates of existing resources. Changes to existing resources may result from new drilling or from revisions to forecast recovery estimates such as from planned use of new technology. Changes may also occur due to fiscal regime changes, changes in equity for existing assets, modifications to depletion plans, and from ongoing geoscience and engineering evaluations. Volumes produced or sold during the year are removed from the resource base at year end.
Effective use of ExxonMobil’s proprietary processes and best practices has resulted in continued low finding and resource-acquisition costs. In 2008 finding and resource-acquisition costs were $1.32 per oil-equivalent barrel. The timing of large resource additions varies from year to year and can lead to fluctuations in finding and resource-acquisition costs. The five-year average finding and resource-acquisition cost is $0.66 per oil-equivalent barrel.
See Frequently Used Terms on pages 96 through 99.
 
Resource Base Changes
                 
            5-Year  
(billions of oil-equivalent barrels)   2008     Average  
 
               
Resource additions/acquisitions
    2.2       3.2  
Revisions to existing fields
          (0.5 )
Production
    (1.5 )     (1.6 )
Sales
    (0.4 )     (1.0 )(1) 
   
Net change
    0.3       0.1  
 
Resource Base(2)
(GRAPHICS)
 
Resource Additions and Acquisitions(2)
(GRAPHICS)
 
Finding and Resources-Acquisition Costs(2)
(GRAPHICS)
 
(1)   Includes impact of the Venezuela expropriation in 2007.
 
(2)   See Frequently Used Terms on pages 96 through 99.



ExxonMobil’s industry-leading resource base of 72 billion oil-equivalent barrels is diverse in terms of resource type and geography.

Resource Base by Type
(percent, oil-equivalent barrels)
(GRAPHICS)
Resource Base by Geographic Region
(percent, oil-equivalent barrels)
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PROVED RESERVES
At year-end 2008, the resource base included 22.8 billion oil-equivalent barrels of proved oil and gas reserves, equating to 15 years of reserves life at current production rates. These reserves are evenly distributed between liquids and gas, and represent a diverse, global portfolio.
In 2008 ExxonMobil replaced 103 percent of reserves produced, including asset sales, by adding 1.53 billion oil-equivalent barrels to proved reserves while producing 1.49 billion oil-equivalent barrels. Key additions came from our operations in Canada, West Africa, Australia, Norway, and the United States. Excluding asset sales, ExxonMobil replaced 110 percent of reserves.
ExxonMobil has added 8.6 billion oil-equivalent barrels to proved reserves over the last five years, more than replacing production. In that time frame, the development of new fields and extensions of existing fields have added an average of 1.2 billion oil-equivalent barrels per year to proved reserves. Revisions have averaged about 0.6 billion oil-equivalent barrels per year over the last five years, driven by effective reservoir management and the application of new technology.
The annual reporting of proved reserves is a product of ExxonMobil’s rigorous and structured management review process that is stewarded by a team of experienced reserves experts with global responsibilities. ExxonMobil calculates its reserves using the same pricing basis used to make investment decisions, consistent with long-standing practice, rather than single-day, year-end pricing.
Production Volumes
In 2008 oil-equivalent production of 3.9 million barrels per day was down 6 percent compared to 2007. Liquids production was 2.4 million barrels per day. Natural gas production available for sale totaled 9.1 billion cubic feet per day. Excluding entitlement volume effects, the Venezuela expropriation, and divestments, oil-equivalent production was down about 3 percent, primarily due to maintenance activities, hurricanes, and natural field decline, partially offset by new project volumes.
Proved Reserves(1)
(billions of oil-equivalent barrels, year-end 2008)
(GRAPHICS)
Proved Reserves Replacement(1)(2)
(percent of annual production replaced with proved reserves additions)
(GRAPHICS)
 
(1) Excludes year-end price/cost effects. Proved reserves reflecting December 31 prices can be found on pages 67-68.
 
(2) Includes asset sales and the 2007 Venezuela expropriation.
 
Looking ahead new projects and work programs are expected to more than offset production declines in existing mature fields. Near-term production growth will be driven by large gas projects in Qatar. Longer-term growth will be enhanced by a diverse portfolio of projects in Africa, Asia Pacific/Middle East, Europe, North America, and the Russia/Caspian regions.
The forward-looking projections of production volumes in this document are reflective of our best assumptions regarding technical, commercial, and regulatory aspects of existing operations and new projects. Factors that could have an impact on actual volumes include project start-up timing, regulatory changes, quotas, asset sales, operational outages, severe weather, and entitlement volume effects under certain production sharing contracts and royalty agreements.


See Frequently Used Terms on pages 96 through 99.


 

Production Outlook

By Type
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By Geographic Region
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Worldwide Upstream Operations

ExxonMobil has interests in exploration and production acreage in 38 countries and production operations in 23 countries.

The Americas
ExxonMobil’s operations in the Americas accounted for approximately 25 percent of ExxonMobil’s 2008 net oil and gas production and about 28 percent of Upstream earnings. Base production continues to yield strong returns. We expect future production to include contributions from unconventional gas, heavy oil, deepwater, and arctic developments.
United States
ExxonMobil is one of the largest oil and gas producers and reserves holders in the United States, with a diverse resource and asset portfolio. ExxonMobil maintains a significant position in all major producing regions, including the Gulf of Mexico/Gulf Coast, the mid-continent, onshore and offshore California, and Alaska. The portfolio contains a diverse range of assets from mature fields to new, world-scale projects.
The United States continues to provide a significant contribution to ExxonMobil’s profitability through high-quality drilling programs, selective investments in existing fields and new projects, continued operational efficiency, and technological improvements.


Americas Highlights
                         
    2008     2007     2006  
 
                       
Earnings (billions of dollars)
    9.8       7.6       8.9  
Proved Reserves(1) (BOEB)
    7.2       6.2       6.2  
Acreage (gross acres, million)
    56.4       56.3       56.4  
Net Liquids Production (MBD)
    0.7       0.7       0.8  
Net Gas Available for Sale (BCFD)
    1.9       2.3       2.5  
 
         (1)   See Frequently Used Terms on pages 96 through 99.

Americas Production
(millions of oil-equivalent barrels per day)
(GRAPHICS)
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Gulf of Mexico/Gulf Coast • ExxonMobil continues to be a leading oil and gas producer in the offshore Gulf of Mexico with average net production of 48 thousand barrels of liquids per day and 429 million cubic feet of gas per day in 2008. Onshore production in Texas and Louisiana added 63 thousand barrels of liquids per day and 483 million cubic feet of gas per day (net).
In the Gulf of Mexico, ExxonMobil has about 2.7 million acres (gross) under lease and operates about 70 structures. We continue to actively evaluate our large acreage position, including the deepwater Lower Tertiary play, and were awarded 142 blocks during 2008.
ExxonMobil also produces natural gas in Alabama’s Mobile Bay through onshore and offshore production facilities. Natural gas is transported by pipeline to two onshore processing complexes – the Onshore Treating Facility and the Mary Ann/823 Complex. In 2008 the Mobile Bay facilities contributed average net production of 186 million cubic feet of gas per day.
The Thunder Horse project (ExxonMobil interest, 25 percent), a deepwater semisubmersible development in the central Gulf of Mexico, began production in 2008. The facility is designed for peak capacity of 250 thousand barrels of oil per day and 200 million cubic feet of gas per day (gross).
Construction of the Golden Pass LNG regasification terminal in Sabine Pass, Texas, continues to progress and is scheduled for start up in 2010. The terminal will have the capacity to deliver up to 2 billion cubic feet of gas per day to the U.S. market.
 
ExxonMobil produces natural gas in Mobile Bay, Alabama, through 29 offshore platforms and two onshore gas processing complexes.
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ExxonMobil has extended the production life of the Hawkins field, discovered in East Texas in 1940, through the application of enhanced oil recovery techniques.
 
Mid-Continent • ExxonMobil has oil and gas production operations throughout the mid-continent states, including Wyoming, Kansas, Colorado, Oklahoma, and New Mexico. Average net production from these areas was 12 thousand barrels of liquids per day and 371 million cubic feet of gas per day in 2008.
The mid-continent contains some of the most mature assets in ExxonMobil’s portfolio. The application of proprietary technology, including enhanced oil recovery and refracturing techniques, continues to significantly extend production life.
ExxonMobil added to its exploration portfolio by acquiring six leases covering 19,400 acres in the Marcellus shale gas play in Pennsylvania. In 2008 ExxonMobil also participated in exploration drilling in the Woodford shale gas play in the Arkoma Basin in Oklahoma.


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In the Piceance Basin in Colorado, ExxonMobil has approximately 300,000 acres under lease with a potential recoverable resource of over 45 trillion cubic feet of gas (gross). In 2008 significant drilling and construction activities were undertaken to expand the gas gathering and processing system as part of the Piceance Phase 1 project, with start-up expected in early 2009. Opportunities for future expansion to fully develop the resource are being evaluated. Average net production from this area was 65 million cubic feet of gas per day in 2008.
The LaBarge development (ExxonMobil interest, 100 percent) in Wyoming consists of the Tip Top and Hogsback fields and the Shute Creek gas processing plant. The operation includes the longest sour gas pipeline in the United States and the world’s largest helium recovery and Selexol (gas sweetening) plants. Construction of additional compression systems will commence in 2009 to increase sales of carbon dioxide for enhanced oil recovery. In 2008 the LaBarge facilities processed an average of 660 million cubic feet of gross inlet gas per day.
ExxonMobil is also building a commercial demonstration plant adjacent to the Shute Creek plant, where it will use proprietary Controlled Freeze Zone technology. This technology could assist in the development of additional gas resources and facilitates the application of carbon capture and storage to reduce greenhouse gas emissions. The new demonstration plant is scheduled for operational start-up in late 2009.
 
The Harmony platform, located 20 miles offshore Santa Barbara, California, in the Santa Ynez Unit, utilizes extended-reach drilling to increase resource recovery.
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ExxonMobil is installing additional compression systems to increase sales of carbon dioxide and constructing a demonstration plant using the proprietary Controlled Freeze Zone technology at the Shute Creek plant in Wyoming.
 
California Average net production from ExxonMobil’s offshore and onshore California assets averaged 115 thousand barrels of liquids per day and 68 million cubic feet of gas per day in 2008.
The Santa Ynez Unit, located 20 miles offshore Santa Barbara, consists of three platforms in the Pacific Ocean’s Outer Continental Shelf and a processing plant in Las Flores Canyon. ExxonMobil also has a 48-percent equity share in the Aera onshore operations, comprising 15 fields and about 12,000 wells producing a mixture of heavy and conventional oil with associated gas.
Alaska ExxonMobil is among the largest producers in Alaska with average net production of 130 thousand barrels per day of liquids. Key assets include a 36-percent interest in Prudhoe Bay and a 37-percent interest in Point Thomson.
ExxonMobil is actively involved in the co-venturer- operated Prudhoe Bay Western Region development, which will allow new satellite fields to produce into existing infrastructure.
ExxonMobil is the largest holder of discovered gas resources on the North Slope of Alaska. The Alaska Gas project would enable treatment and transportation of natural gas from the Prudhoe Bay and Point Thomson fields to North American gas markets. Securing predictable and durable fiscal terms with the State of Alaska is necessary to establish a commercially viable project.
At Point Thomson, ExxonMobil and other unit interest-holders are progressing activities for a multi-well drilling program.
Coal In early 2009 ExxonMobil sold its interest in the Monterey coal mine and associated assets in Illinois following shutdown of mining operations in December 2007.


 


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Canada
ExxonMobil has a leading position in Canada through its wholly owned affiliate ExxonMobil Canada and majority-owned affiliate Imperial Oil (ExxonMobil interest, 69.6 percent). Through these entities, ExxonMobil is a leading crude oil and natural gas producer in Canada and holds one of the country’s largest resource positions. We also have a significant presence in major projects offshore eastern Canada and a well-established production base with expansion opportunities in western Canada.
Offshore Canada Operations The ExxonMobil-operated Sable Offshore Energy Project (ExxonMobil interest, 51 percent; Imperial Oil interest, 9 percent) in Nova Scotia consists of five producing fields. Production in 2008 averaged 412 million cubic feet of gas per day (gross) and 18 thousand barrels per day (gross) of associated natural gas liquids.
The Hibernia field (ExxonMobil interest, 33 percent) offshore Newfoundland is operated by Hibernia Management and Development Company Ltd., using ExxonMobil personnel and processes. In 2008 Hibernia’s production averaged 139 thousand barrels of oil per day (gross).
The co-venturers of the Hibernia Southern Extension project (ExxonMobil interest, 28 percent) are currently in negotiations with the Newfoundland and Labrador provincial government on the development of additional blocks in the southern part of the Hibernia field.
In 2008 the co-venturer-operated Terra Nova development (ExxonMobil interest, 22 percent) produced about 103 thousand barrels of oil per day (gross). Located in 265 feet of water, Terra Nova consists of a unique, harsh-environment-equipped floating production, storage, and offloading vessel and 27 subsea wells that are expected to recover about 400 million oil-equivalent barrels (gross).
 
The Western Patriot seismic vessel conducted a 3D seismic survey in the arctic environment of the Beaufort Sea, Canada.
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The Hibernia platform offshore Newfoundland, Canada, can store 1.3 million barrels of oil in its gravity-based structure.
 
The Hebron project (ExxonMobil interest, 36 percent) is a heavy oil development located in 300 feet of water offshore Newfoundland. Hebron will be designed for harsh arctic conditions using a gravity-based structure. In 2008 the co-venturers executed facilitating agreements with the Newfoundland and Labrador provincial government and approved ExxonMobil as operator. ExxonMobil is leveraging its extensive global experience with gravity-based structures and arctic project execution to advance the project into front-end engineering and design.
The Orphan Basin is a high-potential exploration area with arctic conditions offshore eastern Canada. ExxonMobil has consolidated its interests into two deepwater exploration blocks totaling 4 million gross acres (ExxonMobil interest, 15 percent; Imperial Oil interest, 15 percent). ExxonMobil operates one of the blocks and the other is co-venturer operated. A second wildcat well is being planned following the first wildcat in 2007.
In 2007 ExxonMobil acquired 100 percent interest in the EL446 Block in the Beaufort Sea (ExxonMobil Canada interest, 50 percent; Imperial Oil interest, 50 percent). The block covers 500,000 acres and is located 75 miles from shore in water depths ranging from 200 to 4000 feet. A 3D seismic survey over part of the area was collected in 2008, and processing is under way. Plans for the first exploration well are progressing in this operationally challenging arctic environment.


 


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Onshore Canada Operations • The Cold Lake field (Imperial Oil interest, 100 percent) and the Syncrude oil sands mining operation (Imperial Oil interest, 25 percent) in Alberta account for the majority of Imperial Oil’s liquids production in western Canada.
In 2008 Cold Lake averaged 147 thousand barrels of oil per day (gross) and Syncrude’s production of synthetic crude averaged 289 thousand barrels per day (gross).
The Cold Lake field in Alberta is the largest thermal in situ heavy oil project in the world. It has over 4000 wells directionally drilled from satellite pads. Cyclic Steam Stimulation is used to recover bitumen as it is too heavy and viscous for conventional production. Plans are in place to examine expansion opportunities at Cold Lake and further enhance recovery by using leading-edge thermal recovery technologies. A commercial application of the proprietary LASER (Liquids Addition to Steam for Enhanced Recovery) technology was implemented in 2007 and preliminary results are encouraging.
The Kearl Oil Sands project (combined ExxonMobil and Imperial Oil interest, 100 percent) is expected to develop a world-class resource in northern Alberta exceeding 4 billion barrels. The planned three-phase development will be an open-pit mining operation with the first phase producing approximately 110 thousand barrels of bitumen per day (gross). Front-end engineering was completed in 2008. Detailed design, equipment procurement, and initial site preparation activities have commenced for the first phase.
The Aurora South project at Syncrude is being planned to further develop the resource base in northern Alberta. Two phases of an open-pit mining operation are planned, which combined would produce about 180 thousand barrels of bitumen per day (gross).
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Syncrude, located in Alberta, Canada, averaged gross production of 289 thousand barrels per day in 2008, and is the largest oil sands mining and upgrading facility in the world.
 
The commercialization and regulatory process continues for the Mackenzie Gas Project in the Mackenzie Delta of Canada’s Northwest Territories. The project includes the development of three onshore fields (ExxonMobil and Imperial Oil hold interests in two of the three fields) containing approximately 6 trillion cubic feet of natural gas (gross). The project will deliver natural gas to North American markets through a 740-mile pipeline system to be built along the Mackenzie Valley.
ExxonMobil has acquired 152,000 net acres since 2007 in the Horn River Basin in northeast British Columbia. Exploration drilling activity to evaluate the Horn River shale gas play began in late 2008.
In 2008, oil sands exploration activities including 2D seismic surveys and core hole drilling operations, were conducted on mining leases previously acquired by ExxonMobil and Imperial Oil in the Athabasca area of Alberta, Canada. Further oil sands exploration activity is planned.


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South America
Brazil ExxonMobil holds a 40-percent interest and operatorship of Block BM-S-22, located in the high-potential subsalt play of the Santos Basin offshore Brazil. BM-S-22 is a 342,000-acre block in water depths over 7400 feet and is located approximately 220 miles south of Rio de Janeiro. A 3D seismic survey was acquired in 2005 and processed in 2006.
The first wildcat well on the block commenced drilling in October 2008 utilizing the West Polaris drillship. Plans are ongoing for follow-up wells.
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The West Polaris drillship spud the first exploration well on the ExxonMobil-operated BM-S-22 Block, offshore Brazil in October 2008.
 
Colombia ExxonMobil holds a 40-percent interest in the Tayrona block. This is a 5.5-million-acre block with water depths up to 10,500 feet in the Caribbean Sea, off the northern coast of Colombia. Further drilling plans are being assessed to ensure thorough exploration of this large block.

In 2008 ExxonMobil was awarded a Technical Evaluation Agreement for Block CPE-3 covering 6.4 million acres onshore Colombia. The block is located in a remote and unexplored area of the eastern Llanos Basin on trend with the Orinoco heavy oil belt in Venezuela to the north. ExxonMobil is currently planning an exploration program that is expected to begin in 2009 with the acquisition of 2D seismic data. ExxonMobil will leverage its vast experience in heavy oil to evaluate and develop this potential resource.
Venezuela The Cerro Negro and La Ceiba assets of ExxonMobil affiliates were expropriated without compensation by Venezuela on June 27, 2007. Prior to expropriation, ExxonMobil affiliates owned 412/3-percent interest in Cerro Negro and 50-percent interest in La Ceiba. ExxonMobil affiliates filed an arbitration against Venezuela with the International Centre for Settlement of Investment Disputes (ICSID) in September 2007. An affiliate filed a related arbitration against Venezuela’s national oil company (PdVSA) and a PdVSA affiliate with the International Chamber of Commerce (ICC) in January 2008.
Other South America In Argentina, ExxonMobil holds a 51-percent interest in the Chihuidos field and a 23-percent interest in the Aguarague concession. In 2008 net daily gas production of 64 million cubic feet was sold into markets in Argentina and Chile. In addition the company holds exploration rights in the Stabroek block offshore Guyana. A new 2D seismic survey on the block is currently being processed.


 


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Europe
ExxonMobil is one of the largest producers of oil and natural gas in Europe. The company has upstream interests in Norway, the United Kingdom, the Netherlands, Germany, Italy, Hungary, Romania, Greenland, and Ireland. Extensive North Sea oil and natural gas production operations and significant onshore natural gas production are among the company’s key assets. ExxonMobil’s operations in Europe accounted for about 28 percent of the company’s 2008 net oil and gas production and about 28 percent of Upstream earnings.

The North Sea continues to make a significant contribution to ExxonMobil’s overall production. On the continent ExxonMobil has significant gas holdings in the Netherlands and is the largest gas producer in Germany. Activities continue in all sectors, from exploration to execution of new projects and implementation of work programs that maximize recovery in mature assets.
Exploration activities continue offshore Ireland, Greenland, and the North Sea, and onshore Germany. In 2008 exploration activity was initiated in Hungary and Romania. Major projects under way include new regasification terminals in the United Kingdom and Italy to deliver liquefied natural gas (LNG) to meet growing demand.


Europe Highlights
                           
      2008     2007     2006  
 
                         
 
Earnings (billions of dollars)
    9.9       6.1       6.5  
 
Proved Reserves(1) (BOEB)
    3.4       3.8       3.9  
 
Acreage (gross acres, million)
    27.0       24.3       18.8  
 
Net Liquids Production (MBD)
    0.4       0.5       0.5  
 
Net Gas Available for Sale (BCFD)
    4.0       3.8       4.1  
 
(1)   See Frequently Used Terms on pages 96 through 99.
 
Europe Production
(millions of oil-equivalent barrels per day)
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Norway
ExxonMobil is among the largest oil and gas producers in Norway, with average net production of 295 thousand barrels per day of liquids and 764 million cubic feet per day of gas in 2008.
ExxonMobil operates four major producing fields in Norway including Ringhorne (ExxonMobil interest, 100 percent) and Ringhorne East (ExxonMobil interest, 77 percent), which are located 110 miles west of Stavanger. Since coming onstream in 2003, Ringhorne has produced 167 million barrels of oil and production averaged 92 thousand oil-equivalent barrels per day (gross) in 2008.
Development drilling at the Ormen Lange field (ExxonMobil interest, 7 percent) continued to progress in 2008. Gas from the Ormen Lange field has been flowing since September 2007, and six wells are currently producing at a gross rate of 1.8 billion cubic feet per day of gas.
The Volve field offshore Norway began production in February 2008 (ExxonMobil interest, 30 percent) as an eight-well development. The project is expected to recover nearly 70 million oil-equivalent barrels with a gross production capacity of 50 thousand barrels per day of liquids and 30 million cubic feet per day of gas.
 
Commissioning activities are nearing completion at the South Hook LNG regasification terminal in Milford Haven, Wales, with the first liquefied natural gas (LNG) cargo expected in early 2009.
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The Scottish Area Gas Evacuation (SAGE) plant processes gas from the Beryl Area fields for supply to the U.K. market.
 
The Tyrihans field (ExxonMobil interest, 12 percent) is located in the Norwegian Sea. The field is currently being developed with subsea wells tied back to the Kristin platform for offshore processing and export. First production is expected in 2009.
In 2008 ExxonMobil participated in a successful appraisal of the Nyk High area, adjacent to the 1997 Luva discovery (ExxonMobil interest, 15 percent).
United Kingdom
ExxonMobil is one of the largest oil and gas producers in the United Kingdom, with average net production of 123 thousand barrels per day of liquids and 750 million cubic feet per day of gas in 2008.
ExxonMobil operates eight fields in the northern North Sea and has interests in over 40 producing fields that are co-venturer operated.
ExxonMobil is the operator of the Scottish Area Gas Evacuation (SAGE) gas plant at St. Fergus and the SAGE pipeline that transports gas from the Beryl Area fields to the gas plant. The company’s operations at Beryl and the SAGE gas plant are key contributors to U.K. energy supply.
In the central North Sea, production from the Starling gas condensate field (ExxonMobil interest, 72 percent) began in January 2008. The development consists of up to three wells tied back to the Shearwater platform over 20 miles away and is expected to recover almost 40 million oil-equivalent barrels (gross).
The South Hook LNG regasification terminal in Milford Haven, Wales, is expected to receive its first cargo in early 2009. This terminal will have the capacity to deliver up to 2 billion cubic feet of gas per day into the U.K. natural gas grid.
Preparations are under way to drill a wildcat well on ExxonMobil’s Mid North Sea High license in 2009.


 


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The Netherlands
ExxonMobil is among the largest gas producers in the Netherlands, primarily through its shareholding in NAM (Nederlandse Aardolie Maatschappij), a 50-percent ExxonMobil equity company that produces gas from more than 100 fields located both onshore and offshore. In 2008 ExxonMobil’s net production averaged 1.7 billion cubic feet of gas per day.
NAM is the largest gas producer in the Netherlands. Seventy percent of its production comes from the Groningen field, which is the largest gas field in Western Europe. Discovered in 1959, Groningen is expected to recover over 100 trillion cubic feet of gas. A major renovation project has been progressing in phases since 1997 to ensure natural gas supply from the field continues well into the future. The project is expected to be completed in 2009.
NAM’s Schoonebeek Redevelopment project continued to progress in 2008. This enhanced oil recovery steamflood project is expected to recover 120 million barrels of oil (gross). The project start-up is planned for 2010.
Germany
ExxonMobil is Germany’s largest gas producer with average net production of 687 million cubic feet per day of gas in 2008. A total of 55 ExxonMobil-operated gas fields account for about three-quarters of all natural gas produced in the country.
Approximately half of the gas production is sour, containing up to 36 percent hydrogen sulfide. The sour gas is processed at the Grossenkneten or NEAG sulfur-recovery plants. ExxonMobil also operates a number of large compressor stations to maximize field production and resource recovery.
ExxonMobil’s portfolio in Germany also includes new unconventional gas exploration opportunities. ExxonMobil
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The Groningen natural gas field is the largest in Western Europe and has been producing since 1963.
 
subsidiaries were awarded four large exploration licenses in 2007 by the Lower Saxony and North Rhine-Westphalia states. The licenses cover 1.3 million acres of the Lower Saxony Basin, and ExxonMobil operates these licenses with a 67-percent interest. Drilling and testing activities commenced in 2008.
In 2008 ExxonMobil sold its interest in approximately 2300 miles of regional gas pipeline networks in northern Germany held through BEB Transport GmbH (ExxonMobil interest, 50 percent) and ExxonMobil Gastransport Deutschland GmbH (ExxonMobil interest, 100 percent) to N.V. Nederlandse Gasunie.
 
Drilling activities are under way in the Lower Saxony Basin, Germany, to explore for unconventional gas resources to help increase natural gas supplies in Europe.


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Italy
Adriatic LNG Terminal The Adriatic LNG terminal, installed at its final destination in September 2008, is the world’s first fixed offshore liquefied natural gas (LNG) storage and regasification terminal. The concrete, gravity-based structure, containing two large cryogenic tanks and supporting topside regasification equipment, was towed 1700 nautical miles from Algeciras, Spain, to offshore Porto Levante, Italy, in the northern Adriatic Sea. LNG ships, primarily from Qatar, will discharge cargo at the terminal where the LNG will be converted back into gas for delivery to shore via an export pipeline. The terminal will supply up to 775 million cubic feet of gas per day (gross) to the Italian market. Commissioning activities are progressing with start-up scheduled in 2009.
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The Adriatic LNG terminal was towed from its construction site in Algeciras, Spain, to its final destination offshore Porto Levante, Italy. Commissioning activities are under way for start-up in 2009.
 


Tempa Rossa The Tempa Rossa project (ExxonMobil interest, 25 percent) includes a centralized oil and gas processing facility and a separate liquefied petroleum gas (LPG) terminal with new storage and offloading facilities at a refinery in southern Italy. Site civil work was initiated in 2008 and construction of the oil facilities and export system is expected to begin in 2009. Upon completion these facilities will produce at a peak rate of 50 thousand barrels of oil per day (gross) along with associated natural gas and LPG. The project is expected to develop over 200 million oil-equivalent barrels (gross).

Ireland
In the Porcupine Basin, a frontier area approximately 125 miles off the southwest coast of Ireland, ExxonMobil has interest in four licenses. Evaluation of a 2D seismic survey is progressing on the 320,000-acre Dunquin license in support of potential future drilling (ExxonMobil interest, 80 percent). Two new exploration licenses were awarded to ExxonMobil in 2008, totaling 778,700 acres (ExxonMobil interest, 80 percent). A 2D seismic survey was acquired in 2008 and evaluation of this data is ongoing.
Hungary
ExxonMobil signed two agreements in Hungary to begin exploration in the Mako Trough. The agreements cover adjacent license areas of 184,300 acres (ExxonMobil interest, 33.5 percent) and 386,800 acres in which ExxonMobil will acquire a 50-percent interest upon completion of a work program. ExxonMobil is the operator of both licenses and is conducting an initial work program involving drilling and testing exploratory wells. The initial phase began in 2008.
Romania
ExxonMobil signed an agreement to farm-in to the 1.8-million-acre, deepwater Neptun Block in the Romanian Black Sea (ExxonMobil interest, 50 percent) in 2008. A 3D seismic program is planned in 2009. Following the evaluation of the 3D seismic data, ExxonMobil will have the option to participate in an exploration drilling program.
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Exploration activities in the Mako Trough, Hungary, commenced in 2008.
 
Greenland
In the Disko area of western Greenland, ExxonMobil has interests in Block 6 (ExxonMobil interest, 44 percent) and Block 4 (ExxonMobil interest, 29 percent) totaling nearly 6.7 million acres. In 2008, 2000 miles of 2D data were acquired in each of the two blocks using solid seismic streamers to reduce the potential for fluid spills. ExxonMobil is a leader in the application of this recently developed seismic-streamer technology. The data are currently being processed to identify potential drilling opportunities.


 


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Africa
ExxonMobil is one of the largest oil and gas producers in Africa. ExxonMobil’s operations in Africa accounted for about 17 percent of the company’s 2008 net oil and gas production and 18 percent of Upstream earnings, with those percentages expected to increase as new projects begin production.

ExxonMobil has exploration operations in Angola, Nigeria, Libya, Madagascar, and the Republic of Congo. In deepwater areas offshore Africa, ExxonMobil holds interests in 31 blocks, totaling more than 25 million gross acres, and participated in 16 West Africa deepwater exploration wells that were completed in 2008. ExxonMobil is also progressing liquefied natural gas (LNG) opportunities in the region.
Angola
ExxonMobil has interests in four deepwater blocks that cover more than 3 million gross acres. The company and its co-venturers have announced a total of 60 discoveries in Angola, representing world-class development opportunities with a recoverable resource potential of about 14 billion oil-equivalent barrels (gross).
In 2008 the Kizomba C development, utilizing twin floating production, storage, and offloading vessels for the Mondo and Saxi/Batuque projects, started up on ExxonMobil-operated Block 15. Including production from the co-venturer-operated Block 17, ExxonMobil’s net production in Angola averaged 181 thousand barrels of oil per day in 2008. Development planning for new discoveries in Block 31 and Block 32 is progressing.
Angola Block 15 ExxonMobil was awarded Block 15 in 1994 (ExxonMobil interest, 40 percent), and the first discovery was made in 1998. To date a total resource of nearly 5 billion oil-equivalent barrels (gross) has been discovered on the block. First oil was produced in November 2003 from the Xikomba field, followed by Kizomba A in 2004, Kizomba B in 2005, and Marimba North in 2007.


Africa Highlights
                           
      2008     2007     2006  
 
                         
 
Earnings (billions of dollars)
    6.4       5.5       5.5  
 
Proved Reserves(1) (BOEB)
    2.1       2.4       2.4  
 
Acreage (gross acres, million)
    42.4       41.8       41.1  
 
Net Liquids Production (MBD)
    0.6       0.7       0.8  
 
Net Gas Available for Sale (BCFD)
                 
 
(1)   See Frequently Used Terms on pages 96 through 99.
 
Africa Production
(millions of oil-equivalent barrels per day)
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The Kizomba C Mondo project is a subsea tieback of three drill centers to a floating production, storage, and offloading (FPSO) vessel with a capacity of 100 thousand barrels of oil per day.
 

The Kizomba C Mondo project started up in January 2008 followed by the Kizomba C Saxi/Batuque project in July. Together these projects are expected to recover approximately 600 million barrels of oil (gross). Total combined daily production on the block peaked at over 700 thousand barrels per day (gross) in 2008.
Additional Block 15 developments are progressing including the Gas Gathering project to collect and transport block-wide associated gas to the Angola liquefied natural gas (LNG) facility under construction at Soyo. Activities are also progressing for the Kizomba Satellites project that will include subsea tiebacks to the Kizomba A and B floating production, storage, and offloading (FPSO) vessels. Planning for development continues for the remaining discovered resources on Block 15.
Angola Block 17 ExxonMobil owns a 20-percent interest in Block 17, where the first discovery was made in 1996. Through year-end 2008, 15 discoveries have been announced on the block with a total resource estimate of about 6 billion oil-equivalent barrels. A number of projects have started up, including Girassol in 2001, Dalia in 2006, and Rosa in 2007. During 2008, production was 500 thousand barrels per day (gross). Project execution began in 2008 for the Pazflor project, located 100 miles offshore in 2600 feet of water. An FPSO vessel will be used to produce 200 thousand barrels per day (gross). The next
planned development will be Cravo-Lirio-Orquidea-Violeta (CLOV), another FPSO vessel project that is expected to produce 160 thousand barrels per day (gross).
Angola Block 31 ExxonMobil was awarded a 25-percent interest in Block 31 in 1999, and the first discovery was made in 2002. Through year-end 2008, 16 discoveries have been announced with a total resource of approximately 2 billion oil-equivalent barrels on the block. The first development is the Plutao-Saturno-Venus-Marte (PSVM) hub located in the northern part of the block. A single, 150-thousand-barrel-per-day FPSO vessel is planned for the four fields to produce an estimated 490 million barrels of oil (gross). The water depth ranges from 5900 to 6700 feet, the deepest yet for a West African development project. Planning for development of additional hubs in the southeast and central part of the block is under way.
Angola Block 32 ExxonMobil was awarded a 15-percent interest in Block 32 in 1999 and the first discovery was made in 2003. Through year-end 2008, 12 discoveries have been announced with a total resource of approximately 1.4 billion oil-equivalent barrels on the block. The first development being planned is the AB32 Southeast Hub in the east-central part of the block. A single FPSO vessel is planned to develop a combined resource of up to 650 million barrels of oil (gross). The water depth ranges from 4700 to 5600 feet. Planning for additional exploration wells is ongoing.


 


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Nigeria
ExxonMobil is active on both shallow and deepwater acreage in Nigeria. In shallow water, ExxonMobil operates a joint venture with the Nigerian National Petroleum Corporation (ExxonMobil interest, 40 percent for crude and condensate; 51 percent for natural gas liquids) that covers approximately 800,000 acres in four leases offshore southeastern Nigeria. In deep water, ExxonMobil acquired equity in OPL 223 (ExxonMobil interest, 27 percent) in 2008 and has interests in six other blocks that include the Bonga, Bosi, Erha, Uge, and Usan discoveries. In 2008 ExxonMobil produced an average of 364 thousand barrels of liquids per day (net) offshore Nigeria.
Nigeria Deepwater Development
ExxonMobil continues to progress Nigeria deepwater projects in various stages of development. The ExxonMobil-operated Erha North Phase 2, Bosi, and OPL 214 Uge projects are in the development planning stage. The co-venturer-operated Usan project began execution in early 2008, while development planning continues for the co-venturer-operated Bonga North, Northwest, and Southwest projects.
Erha/Erha North The world-class Erha development (ExxonMobil interest, 56 percent) is located 60 miles offshore in 3900 feet of water. Erha and Erha North started up in 2006 as ExxonMobil’s first operated deepwater production in Nigeria. The combined development consists of over 30 subsea wells tied back to a floating production, storage, and offloading (FPSO) vessel, with a capacity of over 200 thousand barrels per day. Planning continues for the Erha North Phase 2 project that will further develop the Erha North field with additional production wells tied back to the existing Erha FPSO. Exploration efforts continued in 2008 with the 14th exploration well discovering additional hydrocarbons near the Erha/Erha North development.
(GRAPHICS)
(GRAPHICS)
The Erha FPSO has tiebacks to over 30 subsea wells with a capacity of over 200 thousand barrels per day.
 
Bosi The Bosi development (ExxonMobil interest, 56 percent) in over 5500 feet of water will be ExxonMobil’s deepest operated development to date. The Bosi resource will be developed in phases with subsea tiebacks to a spread-moored FPSO vessel. The combined phases of the Bosi project are expected to develop approximately 500 million barrels of oil (gross). Development planning work continues on gas disposition.
Bonga North and Northwest The Bonga North and Bonga Northwest (ExxonMobil interest, 20 percent) subsea development opportunities are progressing and are planned as tiebacks to the existing Bonga Main FPSO that began operation in 2005. These two projects combined would develop about 570 million barrels of oil (gross). Exploration activity included an additional exploratory well in 2008. The results of this well will be used to update the resource potential and development strategy.
Bonga Southwest The Bonga Southwest project (ExxonMobil interest, 16 percent) is planned as an FPSO vessel development with a dedicated gas export pipeline. This development is planned to produce 140 thousand barrels per day at peak production. Design and contracting activities are advancing.
OPL 214 The Uge field (ExxonMobil interest, 20 percent) was discovered in 2005 after ExxonMobil was awarded operatorship of OPL 214 in 2001. The block continues to be evaluated with an appraisal well drilled in 2008. Planning for development continues on Uge, as well as additional exploration drilling on the block.
Usan The Usan project (ExxonMobil interest, 30 percent) is a co-venturer-operated development located 60 miles offshore Nigeria in 2500 feet of water. The development is designed to recover over 500 million barrels of oil (gross) with 42 subsea wells connected to a 180-thousand-barrel-per-day capacity FPSO vessel. Project execution began in 2008.


 


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Nigeria Joint Venture — Shelf Development
In the joint venture area, activities are progressing to increase production capacity as well as develop additional resources. Production growth will result from development drilling, enhanced oil recovery including the Etim/Asasa and Usari Pressure Maintenance projects, and a series of platform upgrades that will expand capacity while also extending the life of the existing assets.
East Area NGL II The East Area natural gas liquids (NGL) II project (ExxonMobil interest, 51 percent) began production in 2008. The project includes an offshore natural gas liquids extraction complex, more than 125 miles of new natural gas and natural gas liquids pipelines, and expansion of the existing onshore Bonny River terminal for fractionation of the liquids into commercial products and offloading. The development will recover about 300 million barrels of natural gas liquids (gross) and is part of an integrated approach to reduce flaring and emissions.
Satellite Field Development The Satellite Field Development project (ExxonMobil interest, 40 percent) targets 20 undeveloped oil fields and 15 infill platform opportunities with total recoverable resources exceeding 1 billion barrels of oil (gross).
Equatorial Guinea
ExxonMobil is the largest producer in Equatorial Guinea operating the Zafiro field (ExxonMobil interest, 71 percent) in water depths between 400 and 2800 feet. In 2008 Zafiro production averaged 184 thousand barrels of oil per day (gross) through the Serpentina FPSO, the Jade Platform, and the Zafiro Producer, a floating production unit.
(GRAPHICS)
Chad
ExxonMobil is the primary producer in Chad with gross average production in 2008 of 127 thousand barrels of oil per day (ExxonMobil interest, 40 percent). Development drilling is focused in the Three Fields area (Kome, Miandoum, and Bolobo). The Maikeri field began production in 2007, and the Timbre field is expected to begin production in 2009. Waterflood projects and production optimization are continuing to maximize recovery of reserves.
Madagascar
In 2004 and 2005, ExxonMobil captured a large acreage position and currently holds over 17 million acres (gross) in four frontier exploration blocks offshore northwestern Madagascar. ExxonMobil has implemented a phased approach to its exploration program. Through year-end 2008, activity has included acquisition of new 2D and 3D seismic data.
Congo
ExxonMobil was awarded a 30-percent interest in the Mer Tres Profonde Sud block in 1997. The first discovery was made in 2000. Through year-end 2008, five discoveries have been announced with a total gross resource of approximately 500 million oil-equivalent barrels on the block. Planning for development is under way. The water depth ranges from 6200 to 6900 feet. The exploration program continues with a new 3D seismic survey acquired in 2007.
ExxonMobil was awarded a 40-percent interest in the Mer Tres Profonde Nord block in 1997. Exploration activities continue with the 3D seismic survey acquired in 2007.
Libya
Additional 2D seismic data and an R3M survey were completed over Contract Area 44 offshore northeastern Libya in 2008. Evaluation of these data is in progress.
Acquisition of a 2D seismic survey, a 3D seismic survey, and an R3M survey were completed over Contract Area 20 offshore northern Libya in 2008. Evaluation of these data is in progress.
Contract Area 21 was awarded to ExxonMobil in June 2008. The contract area comprises 2.5 million acres and is 110 miles offshore in water depths ranging from approximately 5400 to 8700 feet. A 2D seismic survey was completed in 2008 and a 3D seismic survey is planned for 2009. Evaluation of the 2D seismic data is in progress.
 
Additional drilling activity is planned during 2009 from the Jade Platform, offshore Equatorial Guinea, to maximize resource recovery from the Zafiro field.


 


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Asia Pacific/Middle East
ExxonMobil’s operations in the Asia Pacific/Middle East region accounted for about 26 percent of the company’s 2008 net oil and gas production and about 17 percent of Upstream earnings. Those percentages are expected to grow in the future, primarily driven by new developments in Qatar.

Australia
ExxonMobil continues to be a leading oil and gas producer in Australia. In 2008 net production averaged 59 thousand barrels of liquids and 358 million cubic feet of gas per day.
The Kipper/Tuna (ExxonMobil interest, Kipper 32.5 percent, Tuna 50 percent) and Turrum (ExxonMobil interest, 50 percent) projects in the Bass Strait are in the execution stage.
The Gorgon Jansz project (ExxonMobil interest, 25 percent) is in the final stages of obtaining government approvals to develop this world-class gas resource offshore Western Australia. The development consists of subsea infrastructure for the production and transport of gas and a 15-million-tons-per-year liquefied natural gas (LNG) facility located on Barrow Island. The development concept for the ExxonMobil-operated Jansz field includes one of the world’s longest subsea tiebacks, located in over 4200 feet of water.
Appraisal drilling in 2009 and beyond will enhance opportunities to further develop the existing discovered resources of 40 trillion cubic feet of gas (gross).
Development and execution planning continues to progress for the Scarborough LNG project (ExxonMobil interest, 50 percent). The field is located offshore Western Australia and has a resource of approximately 10 trillion cubic feet of gas (gross).
Exploration evaluation activities continue in the WA-392-P, WA-374-P, and WA-268-P blocks (ExxonMobil interest, 25 percent). In 2008 a 3D seismic survey was acquired in the WA-268-P block and ExxonMobil completed acquisition of a new 2D seismic survey in the WA-318-P block (ExxonMobil interest, 75 percent) in the Bonaparte Basin offshore northern Australia.


Asia Pacific/Middle East Highlights
                           
      2008     2007     2006  
 
                         
 
Earnings (billions of dollars)
    6.2       4.9       4.1  
 
Proved Reserves(1) (BOEB)
    8.2       8.3       8.1  
 
Acreage (gross acres, million)
    26.9       29.0       21.7  
 
Net Liquids Production (MBD)
    0.5       0.5       0.5  
 
Net Gas Available for Sale (BCFD)
    3.1       3.2       2.6  
 
     
(1)   See Frequently Used Terms on pages 96 through 99.
 
Asia Pacific/Middle East Production
(millions of oil-equivalent barrels per day)
(GRAPHICS)


(GRAPHICS)
(GRAPHICS)
The Gorgon Jansz project includes parallel subsea development of the Gorgon and Jansz fields along with installation of a 15-million-tons-per-year LNG facility on Barrow Island.


 


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Indonesia
ExxonMobil operates Indonesia’s Arun gas field (ExxonMobil interest, 100 percent), which supplies gas to the PT Arun LNG plant. In 2008 net production from the Arun field, Arun satellite fields, and the North Sumatra Offshore field averaged 239 million cubic feet of gas per day.
The Banyu Urip development in the Cepu Contract Area, onshore Java, (ExxonMobil interest, 45 percent) includes an early oil phase with capacity to produce up to 20 thousand barrels of oil per day (gross). The full development is expected to produce 165 thousand barrels of oil per day (gross) and is planned to have 49 wells, an onshore central processing facility, and a 60-mile pipeline to transport the processed oil to a floating storage and offloading vessel. Land acquisition and major contract tendering activities are under way for the full project. In 2008 a successful appraisal well was drilled at the Jambaran field. A Cepu exploration drilling program is planned for the 2009 to 2010 period.
In 2008 ExxonMobil submitted a Plan of Development and communicated intent to enter the next phase of development to the Indonesian government for the Natuna D-Alpha gas field (ExxonMobil interest, 76 percent), a large offshore gas field containing over 70 percent carbon dioxide. Development activity is under way while discussions are continuing with the government to achieve mutually agreeable contract terms.
In 2008 exploration activity continued in the Surumana and Mandar blocks (ExxonMobil interest, 100 percent) offshore Sulawesi in the Makassar Strait. New 3D seismic data were acquired over the Mandar block in 2008 with plans to initiate drilling in the Surumana and Mandar blocks in 2009.
ExxonMobil was awarded the 406,500-acre Gunting Block (ExxonMobil interest, 100 percent) onshore and offshore Java in 2008.
Malaysia
ExxonMobil operates 43 platforms in 17 fields as one of Malaysia’s major suppliers of crude oil and natural gas. Net production in 2008 averaged 56 thousand barrels of liquids per day and 582 million cubic feet of gas per day.
In March 2008, ExxonMobil and the Malaysian national oil company, PETRONAS, agreed to continue to work together to help ensure sustainable energy supplies for Malaysia under a new Production Sharing Agreement. The 25-year agreement includes commitments to implement an enhanced oil recovery project at the Tapis Field, to continue conventional oil development, and to maintain the integrity and reliability of existing offshore facilities using ExxonMobil’s advanced technology and project-execution capabilities.
In early 2008, ExxonMobil started up the Tapis F (ExxonMobil interest, 50 percent) and Jerneh B (ExxonMobil interest, 100 percent) gas platforms in the South China Sea. These projects are expected to deliver peak production of 270 million cubic feet per day of gas (gross) to Peninsular Malaysia.
(GRAPHICS)
Papua New Guinea (PNG)
In 2008 ExxonMobil’s net production averaged 7 thousand barrels of oil per day. The Gas Agreement for the PNG LNG project (ExxonMobil interest, 33 percent) was signed in 2008 by the State of Papua New Guinea and the project’s joint venture participants. After achieving this milestone, the project began front-end engineering and design for the gas processing facilities, pipelines, and LNG plant facilities. The project is planned to develop the Hides, Angore, and Juha fields to supply feed gas for a 6.3-million-tons-per-year LNG facility located 12 miles northwest of Port Moresby.
Philippines
Evaluation of the SC-56 block (ExxonMobil interest, 50 percent) continued with acquisition of a geochemical survey in 2008. Exploration drilling is planned in 2009.
New Zealand
ExxonMobil was awarded the 4-million-acre PEP50117 license (ExxonMobil interest, 90 percent) in the Great South Basin in 2007. In 2008, seismic data were acquired in preparation for a potential exploratory drilling program.
Hong Kong Power
Through a partnership with CLP Holdings, ExxonMobil has a 60-percent interest in the Castle Peak Power Company in Hong Kong with 6900 megawatts of power generation capacity, and a 51-percent interest in 600 megawatts of pumped storage capacity in southern China. The related electricity Scheme of Control Agreement with the Hong Kong government has been renewed for 10 years. An emissions reduction project is under way at the Castle Peak power station.


 


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Qatar
Through the Qatar joint ventures, ExxonMobil and Qatar Petroleum continue to develop the North Field, the largest non-associated gas field in the world. Resources exceeding 25 billion oil-equivalent barrels (gross) will be developed through existing and planned projects with ExxonMobil interest. The North Field is cost-competitive for supplying liquefied natural gas (LNG) to the major markets in Asia, Europe, and North America. By the end of 2009, the world’s four largest LNG trains are expected to be online to further meet the world’s growing energy demand.
LNG production from ExxonMobil-interest trains in Qatar was nearly 31 million tons in 2008 (gross). ExxonMobil participates in all of the existing Qatargas and RasGas trains (ExxonMobil interest ranges from 10 to 34 percent). The Al Khaleej domestic gas operation (ExxonMobil interest, 100 percent) produced about 720 million cubic feet per day in 2008.

Qatar Existing and Planned LNG Trains
                             
Joint       Capacity     Working     Scheduled  
Venture   Train   (MTA)(1)     Interest (%)     Completion  
 
Qatargas
  1,2,3     9.7       10     Complete  
Qatargas II
  4     7.8       30       2009  
 
  5     7.8       18       2009  
RasGas
  1,2     6.6       25     Complete  
 
  3     4.7       30     Complete  
 
  4     4.7       34     Complete  
 
  5     4.7       30     Complete  
 
  6     7.8       30       2009  
 
  7     7.8       30       2009  
 
Total
        61.6                  
 
(1)   Million tons per year.
(GRAPHICS)
RasGas Trains 6 and 7 RasGas is constructing two 7.8-million-tons-per-year LNG trains owned by Ras Laffan Liquefied Natural Gas Company (3), a joint venture between Qatar Petroleum and ExxonMobil. The scope of the project entails the design, construction, and operation of two mega LNG trains and associated facilities to produce approximately 15.6 million tons per year of LNG. Construction of all facilities is progressing with start-up of both Train 6 and Train 7 planned in 2009. Train 6 is planned to supply the U.S. market via the Golden Pass LNG regasification terminal and Train 7 is expected to supply Asia and other markets worldwide.
Qatargas II Trains 4 and 5 Qatargas II Train 4 is expected to start up in early 2009 and will be the first mega LNG train in the world with an annual capacity of 7.8 million tons. Train 5, which also will have an annual capacity of 7.8 million tons, is expected to start up later in 2009. Deliveries from Qatargas II will use a fleet of Q-Flex and Q-Max vessels, the world’s largest LNG carriers. Shipments are planned primarily to the U.K. gas market through the South Hook LNG regasification terminal.


 
Construction and commissioning activities are continuing to progress at the Qatargas II Train 4 and 5 projects. Qatargas II Train 4 is expected to start up in early 2009 and Train 5 will follow later in the year.
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Al Khaleej Gas The second phase of the Al Khaleej Gas project is expected to start up in 2009, supplying 1.25 billion cubic feet per day of natural gas (gross) to meet Qatar’s growing domestic demand and exporting 70 thousand barrels per day of liquids (gross). This is an expansion of Phase 1, which has operated since 2005.
(GRAPHICS)
Barzan The initial phase of the Barzan project will supply domestic gas to meet Qatar’s rapidly growing infrastructure and industry requirements. In 2007 ExxonMobil and Qatar Petroleum signed a Heads of Agreement to develop all future phases of the Barzan project. Front-end engineering and design are under way. The initial phase of the Barzan project is expected to produce about 1.5 billion cubic feet per day of gas (gross).
Qatar Common Facilities RasGas and Qatargas are constructing common facilities on behalf of the Ras Laffan Industrial City joint venture companies for the storage and loading of LNG, condensates, LPG, and sulfur. The utilization of shared facilities enables each participant to benefit from significant economies of scale, resulting in billions of dollars of savings over stand-alone construction. Construction of all facilities is progressing as planned.
United Arab Emirates
ExxonMobil participates in two oil concessions in the United Arab Emirates, one onshore and one offshore. In 2008 the daily net production from the onshore concession was 130 thousand barrels of oil. Daily net production from the Upper Zakum offshore concession was 154 thousand barrels of oil.
Upper Zakum (ExxonMobil interest, 28 percent) is one of the world’s largest oil fields, with approximately 50 billion barrels originally in place, and less than 10 percent of the resource produced to date. ExxonMobil’s capability to improve oil recovery, build production capacity, transfer technology, and develop staff was key to gaining entry to the field in 2006. The ExxonMobil Technology Center in Abu Dhabi is now fully operational to allow staff working on Upper Zakum access to the industry’s most advanced technology in the areas of reservoir management, well management, and production operations.



 
Left: The Q-Max ship (left) and the Q-Flex ship (right) are 80% and 45% larger than conventional-size LNG ships, respectively.
Below: Upper Zakum is one of the world’s largest oil fields. The central facilities, located offshore Abu Dhabi, process crude from 42 wellhead platforms.


(GRAPHICS)

 


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Russia/Caspian
ExxonMobil’s operations in the Russia/Caspian region accounted for about 4 percent of the company’s 2008 net oil and gas production and about 9 percent of Upstream earnings, with these percentages expected to increase as new projects come onstream. In the Caspian, ExxonMobil holds the unique position of participating in the development of three of the largest fields in the world: Kashagan and Tengiz in Kazakhstan, and Azeri-Chirag-Gunashli in Azerbaijan.

Russia
ExxonMobil operates and holds a 30-percent interest in the Sakhalin-1 area, which comprises three offshore fields – Chayvo, Odoptu, and Arkutun-Dagi. The Sakhalin-1 project is one of the largest single foreign investment projects in Russia and is being developed in phases. Production from Chayvo started in 2005.
Exploration activities on the Sakhalin-III blocks are pending resolution of award of exploration and production licenses by the Russian government. ExxonMobil continues to pursue new opportunities to participate jointly with Russian companies in Russia’s energy industry.
Sakhalin-1 Chayvo In 2005 first oil production and gas sales to far east Russia commenced from the initial development phase of Sakhalin-1 Chayvo. The permanent onshore processing facilities and export system were commissioned in 2006. In 2008 gross production averaged 200 thousand barrels of oil per day and 145 million cubic feet of sales gas per day. Future phases will be implemented to maintain capacity utilization of the processing facility and export system and sustain field production for the long term.
In 2006 a Heads of Agreement was signed with China National Petroleum Corporation (CNPC) for gas pipeline sales from Sakhalin-1 to China. Other regional gas sales options also continue to be evaluated.
(GRAPHICS)
(GRAPHICS)
The Yastreb drilling rig, specially built for the harsh arctic conditions in Sakhalin, provides the capacity needed to drill world-class extended-reach wells.
 
Sakhalin-1 Future Phases The next phases of the Sakhalin-1 project include the development of the Odoptu and Arkutun-Dagi fields. Odoptu detailed engineering was completed in 2008 while regulatory approvals and construction activities continued to progress. Arkutun-Dagi’s early engineering activities continued to advance in 2008. Both projects will benefit from the infrastructure and learnings from Chayvo.

Russia/Caspian Highlights
                         
    2008     2007     2006  
 
                       
Earnings (billions of dollars)
    3.1       2.4       1.2  
Proved Reserves(1) (BOEB)
    1.9       2.0       2.1  
Acreage (gross acres, million)
    2.5       2.5       2.7  
Net Liquids Production (MBD)
    0.2       0.2       0.1  
Net Gas Available for Sale (BCFD)
    0.1       0.1       0.1  
 
(1)   See Frequently Used Terms on pages 96 through 99.
 
Russia/Caspian Production
(millions of oil-equivalent barrels per day)
(GRAPHICS)



 


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Azerbaijan
Phase 1 and 2 developments of the Azeri portion of the Azeri-Chirag-Gunashli (ACG) field (ExxonMobil interest, 8 percent) started up in 2005 and 2006, respectively. The Phase 3 development of the Deep Water Gunashli field started up in 2008. Total estimated recovery from the field is 5.4 billion oil-equivalent barrels (gross). In 2008 the ACG field achieved oil production rates in excess of 900 thousand barrels of oil per day (gross) and is expected to reach 1 million barrels per day (gross) by 2010.
Kazakhstan
ExxonMobil participates in the Tengizchevroil (TCO) joint venture (ExxonMobil interest, 25 percent), which includes a production license area encompassing the Tengiz field, an associated processing plant complex, and the nearby Korolev field. Including an exploration license adjacent to the production area, TCO holds a total of 608,000 acres (gross).
ExxonMobil also participates in the North Caspian Production Sharing Agreement, which includes the giant Kashagan field located offshore in the Caspian Sea. In 2008 final agreements were signed that reduced ExxonMobil’s interest from 19 percent to 17 percent. Development activities for the Kashagan Phase 1 project are progressing.
Tengiz The giant Tengiz field in Kazakhstan has produced over 1 billion barrels of oil from a resource of nearly 6 billion barrels (gross). TCO completed a major expansion that included sour gas injection and a second-generation gas-handling project at the Tengiz field in 2008, which increased the daily crude production capacity of the field to 540 thousand barrels of oil per day (gross). A planned future expansion could develop an additional 1 billion barrels of oil and provide a further 370 thousand barrels per day (gross) of incremental capacity.
Kashagan The Kashagan field will be developed in phases. Phase 1, which is currently under construction, includes an offshore production and separation hub on an artificial island, several drilling islands, three onshore oil-stabilization trains, two onshore gas treatment plants, and an onshore sulfur treatment plant. This phase is anticipated to produce 3.6 billion barrels of oil at a production rate of 360 thousand barrels per day (gross). Future phases are expected to increase recovery to 12 billion barrels of oil at a production rate of approximately 1.5 million barrels of oil per day (gross).
(GRAPHICS)
(GRAPHICS)
Production from the Tengiz field increased to 540 thousand barrels of oil per day (gross) following completion of a major expansion project in 2008.
(GRAPHICS)
Artificial islands in the Caspian Sea support the offshore drilling and production activities for the Kashagan Phase 1 development.


 


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Upstream Operating Statistics
NET LIQUIDS PRODUCTION(1) – Including Oil Sands and Non-Consolidated Operations
 
                                         
(thousands of barrels per day)   2008     2007     2006     2005     2004  
 
                                       
United States
                                       
Alaska
    130       132       127       159       174  
Lower 48
    237       260       287       317       383  
Total United States
    367       392       414       477       557  
Canada/South America
    292       324       354       395       408  
Total Americas
    659       716       768       872       965  
         
Europe
                                       
United Kingdom
    123       150       186       202       235  
Norway
    295       319       320       327       328  
Other
    10       11       14       17       20  
Total Europe
    428       480       520       546       583  
         
Africa
                                       
Nigeria
    364       415       427       299       276  
Angola
    181       173       193       181       95  
Equatorial Guinea
    60       76       103       122       136  
Other
    47       53       58       64       65  
Total Africa
    652       717       781       666       572  
         
Asia Pacific/Middle East
                                       
Australia
    59       66       69       73       91  
Malaysia
    56       67       64       82       94  
Middle East
    381       374       340       163       158  
Other
    10       11       12       14       17  
Total Asia Pacific/Middle East
    506       518       485       332       360  
         
Russia/Caspian
    160       185       127       107       91  
         
Total worldwide
    2,405       2,616       2,681       2,523       2,571  
         
 
                                       
Gas Plant Liquids Included Above
                                       
United States
    49       57       61       68       86  
Non-U.S.
    164       166       175       172       168  
         
Total worldwide
    213       223       236       240       254  
         
 
                                       
Oil Sands and Non-Consolidated Volumes Included Above
                       
United States
    78       82       87       93       101  
Canada/South America
    62       65       58       53       59  
Europe
    5       6       6       7       9  
Asia Pacific/Middle East
    193       190       172       146       140  
Russia/Caspian
    87       75       71       72       74  
         
Total worldwide
    425       418       394       371       383  
         
 
(1)   Net liquids production quantities are the volumes of crude oil and natural gas liquids withdrawn from ExxonMobil’s oil and gas reserves, excluding royalties and quantities due to others when produced, and are based on the volumes delivered from the lease or at the point measured for royalty and/or severance tax purposes. Volumes include 100 percent of the production of majority-owned affiliates, including liquids production from oil sands operations in Canada, and ExxonMobil’s ownership of the production by companies owned 50 percent or less.
     
 
         
Proved Reserves per Share Growth
  Production per Share Growth   Upstream Earnings per Share Growth
 
()
  ()   ()
 
(1)   Royal Dutch Shell, BP, and Chevron values are calculated on a consistent basis with ExxonMobil, based on public information.
 
(2)   2008 competitor data not available.

 


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NET NATURAL GAS PRODUCTION AVAILABLE FOR SALE(1) – Including Non-Consolidated Operations
                                         
(millions of cubic feet per day)   2008     2007     2006     2005     2004  
 
United States
    1,246       1,468       1,625       1,739       1,947  
Canada/South America
    640       808       935       1,006       1,069  
Total Americas
    1,886       2,276       2,560       2,745       3,016  
         
Europe
                                       
The Netherlands
    1,748       1,551       1,536       1,595       1,725  
United Kingdom
    750       779       990       1,126       1,196  
Norway
    764       705       686       709       645  
Germany
    687       775       874       885       1,048  
Total Europe
    3,949       3,810       4,086       4,315       4,614  
         
Africa
    32       26                    
         
Asia Pacific/Middle East
                                       
Australia
    358       389       330       338       397  
Malaysia
    582       583       519       488       511  
Middle East
    1,911       1,875       1,353       846       642  
Indonesia
    239       286       365       410       578  
Other
    24       29       29       32       33  
Total Asia Pacific/Middle East
    3,114       3,162       2,596       2,114       2,161  
         
Russia/Caspian
    114       110       92       77       73  
         
Total worldwide
    9,095       9,384       9,334       9,251       9,864  
         
 
                                       
Non-Consolidated Natural Gas Volumes Included Above
                                       
United States
    1       1       1       2       2  
Europe
    1,696       1,503       1,500       1,548       1,667  
Asia Pacific/Middle East
    1,356       1,272       1,000       807       642  
Russia/Caspian
    77       79       75       73       74  
         
Total worldwide
    3,130       2,855       2,576       2,430       2,385  
         
 
(1)   Net natural gas available for sale quantities are the volumes withdrawn from ExxonMobil’s natural gas reserves, excluding royalties and volumes due to others when produced, and excluding gas purchased from others, gas consumed in producing operations, field processing plant losses, volumes used for gas lift, gas injection and cycling operations, quantities flared, and volume shrinkage due to the removal of condensate or natural gas liquids fractions.
NATURAL GAS SALES(1)
                                         
(millions of cubic feet per day)   2008     2007     2006     2005     2004  
 
United States
    1,292       1,560       1,686       1,833       2,277  
Canada/South America
    845       968       1,120       1,186       1,353  
Europe
    5,665       5,396       5,728       6,015       6,262  
Africa
    32       26                    
Asia Pacific/Middle East
    2,841       2,900       2,379       1,901       1,973  
Russia/Caspian
    137       129       112       86       77  
         
Total worldwide
    10,812       10,979       11,025       11,021       11,942  
         
 
(1)   Natural gas sales include 100 percent of the sales of ExxonMobil- and majority-owned affiliates and ExxonMobil’s ownership of sales by companies owned 50 percent or less. Numbers include sales of gas purchased from third parties.

 


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66
 EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW 
 NUMBER OF NET WELLS DRILLED ANNUALLY(1)
 
                                                                                                                         
    Productive     Dry     Total  
                   
 
(net wells drilled)   2008     2007     2006     2005     2004     2008     2007     2006     2005     2004     2008     2007     2006     2005     2004  
 
Exploratory(2)
    19       19       21       24       21       9       16       12       13       15       28       35       33       37       36  
Development
    731       917       1,041       946       1,164       4       19       11       14       18       735       936       1,052       960       1,182  
Total
    750       936       1,062       970       1,185       13       35       23       27       33       763       971       1,085       997       1,218  
   
 NET ACREAGE AT YEAR END(3)
 
                                                                                 
    Undeveloped     Developed  
(thousands of net acres)   2008     2007     2006     2005     2004     2008     2007     2006     2005     2004  
 
United States
    5,691       5,539       6,062       6,413       7,055       5,148       5,174       5,178       5,260       5,480  
Canada/South America(4)
    19,953       22,563       22,224       24,484       25,832       2,488       2,366       2,360       2,498       2,915  
Europe
    7,913       6,002       2,727       2,778       2,245       4,026       4,194       4,418       4,687       4,715  
Africa
    26,439       24,835       24,075       29,048       21,797       756       729       717       545       475  
Asia Pacific/Middle East
    12,190       13,167       7,462       3,797       4,180       1,651       1,649       1,655       1,570       2,436  
Russia/Caspian
    372       392       449       569       561       116       116       116       116       103  
Total worldwide
    72,558       72,498       62,999       67,089       61,670       14,185       14,228       14,444       14,676       16,124  
   
 
                                                                               
 NET CAPITALIZED COSTS AT YEAR END(3)
 
 
                                                                               
(millions of dollars)
                                            2008       2007       2006       2005       2004  
 
                                                                               
United States
                                            18,542       16,948       16,530       16,097       16,217  
Canada/South America(4)
                                            9,967       11,338       10,076       10,306       10,144  
Europe
                                            11,477       15,426       15,182       13,556       16,169  
Africa
                                            17,797       15,149       14,280       12,744       10,706  
Asia Pacific/Middle East
                                            11,379       10,674       8,813       6,718       6,675  
Russia/Caspian
                                            10,219       9,142       8,246       7,158       5,336  
Total worldwide
                                            79,381       78,677       73,127       66,579       65,247  
   
 COSTS INCURRED IN PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT ACTIVITIES(3)
                                                         
            Canada/                     Asia Pacific/     Russia/        
(millions of dollars)   United States     South America(4)     Europe     Africa     Middle East     Caspian     Worldwide  
 
                                                       
During 2008
                                                       
Property acquisition costs
    281       126       25       82       86       63       663  
Exploration costs
    453       325       401       686       346       61       2,272  
Development costs
    2,739       1,421       1,863       4,783       2,063       1,764       14,633  
Total
    3,473       1,872       2,289       5,551       2,495       1,888       17,568  
   
During 2007
                                                       
Property acquisition costs
    63       93             13       15       10       194  
Exploration costs
    377       231       229       584       261       80       1,762  
Development costs
    1,859       902       2,016       2,847       2,405       1,541       11,570  
Total
    2,299       1,226       2,245       3,444       2,681       1,631       13,526  
   
During 2006
                                                       
Property acquisition costs
    54       100       11       16       405       11       597  
Exploration costs
    382       225       202       518       219       139       1,685  
Development costs
    1,838       1,002       2,660       3,433       1,718       1,452       12,103  
Total
    2,274       1,327       2,873       3,967       2,342       1,602       14,385  
   
During 2005
                                                       
Property acquisition costs
    11       18             53       41       330       453  
Exploration costs
    286       134       152       507       181       160       1,420  
Development costs
    1,695       1,177       1,493       3,189       850       2,157       10,561  
Total
    1,992       1,329       1,645       3,749       1,072       2,647       12,434  
   
 
(1)   A regional breakout of this data is included on page 15 of ExxonMobil’s 2008 Form 10-K.
 
(2)   These include near-field and appraisal wells classified as exploratory for SEC reporting.
 
(3)   Includes non-consolidated interests and Canadian oil sands mining operations and is not directly comparable to data in Appendix A of ExxonMobil’s 2009 Proxy Statement, or pages 8 and 9 of ExxonMobil’s 2008 Form 10-K, which due to financial reporting requirements treat Canadian oil sands as a mining operation.
 
(4)   Canadian oil sands data included above: net acreage of 29,000 developed acres and 212,000 undeveloped acres at year-end 2008, net capitalized cost of about $3.3 billion at year-end 2008, exploration costs of $19 million, and development costs of $514 million incurred during 2008.


 


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EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
67
 PROVED OIL AND GAS RESERVES(1)
                                         
    2008     2007     2006     2005     2004  
 
Liquids, Including Oil Sands and Non-Consolidated Reserves (millions of barrels at year end)                    
Net proved developed and undeveloped reserves
                                       
United States
    2,076       2,212       2,177       2,424       2,894  
Canada/South America(2)
    2,717       1,564       1,985       2,152       2,326  
Europe
    566       696       750       886       1,029  
Africa
    2,004       2,180       2,266       2,527       2,654  
Asia Pacific/Middle East
    2,967       2,976       2,765       1,908       1,688  
Russia/Caspian
    1,502       1,632       1,766       1,798       1,922  
Total worldwide excluding year-end price/cost effects
    11,832       11,260       11,709       11,695       12,513  
         
Year-end price/cost effects
    174       (186 )     (141 )     (466 )     (862 )
         
Total worldwide
    12,006       11,074       11,568       11,229       11,651  
         
 
                                       
Proportional interest in oil sands and non-consolidated reserves included above, excluding year-end price/cost effects
                                 
United States
    368       374       369       391       402  
Canada (oil sands)(2)
    1,871       694       718       738       757  
Europe
    27       25       12       11       17  
Asia Pacific/Middle East
    1,350       1,420       1,399       1,353       1,161  
Russia/Caspian
    806       850       909       923       981  
Net proved developed reserves included above
                                       
United States
    1,521       1,626       1,777       2,006       2,551  
Canada/South America
    1,315       1,376       1,620       1,344       1,218  
Europe
    419       526       568       665       778  
Africa
    1,284       1,202       1,279       1,218       1,117  
Asia Pacific/Middle East
    1,964       1,797       1,720       1,189       1,045  
Russia/Caspian
    715       602       652       629       634  
         
Total worldwide
    7,218       7,129       7,616       7,051       7,343  
         
 
                                       
Natural Gas, Including Non-Consolidated Reserves (billions of cubic feet at year end)                        
Net proved developed and undeveloped reserves
                                       
United States
    12,847       13,255       10,231       11,362       10,578  
Canada/South America
    1,376       1,547       1,952       2,354       2,748  
Europe
    17,097       18,539       18,847       20,575       21,916  
Africa
    918       1,006       986       841       771  
Asia Pacific/Middle East
    31,149       32,143       31,878       26,662       19,938  
Russia/Caspian
    2,233       2,282       2,103       2,173       1,989  
Total worldwide excluding year-end price/cost effects
    65,620       68,772       65,997       63,967       57,940  
         
Year-end price/cost effects
    259       (510 )     1,563       2,940       2,422  
         
Total worldwide
    65,879       68,262       67,560       66,907       60,362  
         
 
                                       
Proportional interest in non-consolidated reserves included above, excluding year-end price/cost effects
                                 
United States
    118       125       131       136       140  
Europe
    11,644       12,189       11,867       12,340       12,873  
Asia Pacific/Middle East
    21,199       21,596       20,800       18,697       13,339  
Russia/Caspian
    1,446       1,504       1,290       1,326       1,473  
Net proved developed reserves included above
                                       
United States
    7,931       8,477       9,389       10,499       9,254  
Canada/South America
    1,148       1,303       1,628       1,840       1,926  
Europe
    13,710       14,743       15,331       16,558       16,881  
Africa
    738       773       823       376       279  
Asia Pacific/Middle East
    17,996       14,272       13,788       13,343       9,018  
Russia/Caspian
    1,226       1,152       1,258       1,062       841  
         
Total worldwide
    42,749       40,720       42,217       43,678       38,199  
         
 
(1)   See Frequently Used Terms on pages 96 through 99.
(2)   Includes proven reserves from Canadian oil sands operations in Canada and, therefore, is not directly comparable to data shown in Appendix A of ExxonMobil’s 2009 Proxy Statement, which due to financial reporting requirements treat Canadian oil sands as a mining operation.


 


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68
EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
PROVED OIL AND GAS RESERVES REPLACEMENT(1)(2)(3) – Units are million barrels of oil or billion cubic feet of gas unless specified otherwise
                                                 
                                            Average  
    2008     2007     2006     2005     2004     2004-2008  
 
                                               
Liquids (millions of barrels)
                                               
Revisions
    232       708       57       (333 )     97       152  
Improved recovery
    8       35       27       30       22       24  
Extensions/discoveries
    1,297       197       246       516       595       570  
Purchases
                746       113       10       174  
Sales
    (86 )     (436 )     (86 )     (227 )     (132 )     (193 )
 
             
Total additions before year-end price/cost effects
    1,451       504       990       99       592       727  
Remove prior year-end price/cost effects
    186       141       466       862             331  
Current year-end price/cost effects
    174       (186 )     (141 )     (466 )     (862 )     (296 )
Total additions
    1,811       459       1,315       495       (270 )     762  
Production
    879       953       976       917       935       932  
 
             
Reserves replacement ratio, excluding sales (percent)
    175       99       110       36       77       99  
Reserves replacement ratio, including sales (percent)
    165       53       101       11       63       78  
Reserves replacement ratio, including sales and year-end price/cost effects (percent)
    206       48       135       54             82  
               
 
                                               
Natural Gas (billions of cubic feet)
                                               
Revisions
    (127 )     6,509       1,993       4,261       256       2,578  
Improved recovery
    1       4       12       9       37       13  
Extensions/discoveries
    693       323       3,808       5,667       7,282       3,555  
Purchases
          9       57       53       9       25  
Sales
    (82 )     (320 )     (104 )     (229 )     (477 )     (242 )
 
             
Total additions before year-end price/cost effects
    485       6,525       5,766       9,761       7,107       5,929  
Remove prior year-end price/cost effects
    510       (1,563 )     (2,940 )     (2,422 )           (1,283 )
Current year-end price/cost effects
    259       (510 )     1,563       2,940       2,422       1,335  
Total additions
    1,254       4,452       4,389       10,279       9,529       5,981  
Production
    3,637       3,750       3,736       3,734       3,936       3,759  
 
             
Reserves replacement ratio, excluding sales (percent)
    16       183       157       268       193       164  
Reserves replacement ratio, including sales (percent)
    13       174       154       261       181       158  
Reserves replacement ratio, including sales and year-end price/cost effects (percent)
    34       119       117       275       242       159  
               
 
                                               
Oil-Equivalent (millions of barrels)
                                               
Revisions
    211       1,793       390       377       140       582  
Improved recovery
    8       35       29       31       28       26  
Extensions/discoveries
    1,413       251       881       1,461       1,809       1,163  
Purchases
          2       755       122       11       178  
Sales
    (100 )     (490 )     (104 )     (265 )     (211 )     (234 )
 
             
Total additions before year-end price/cost effects
    1,532       1,591       1,951       1,726       1,777       1,715  
Remove prior year-end price/cost effects
    271       (119 )     (24 )     458             118  
Current year-end price/cost effects
    217       (271 )     119       24       (459 )     (74 )
Total additions
    2,020       1,201       2,046       2,208       1,318       1,759  
Production
    1,485       1,578       1,598       1,539       1,591       1,558  
 
             
Reserves replacement ratio, excluding sales (percent)
    110       132       129       129       125       125  
Reserves replacement ratio, including sales (percent)
    103       101       122       112       112       110  
Reserves replacement ratio, including sales and year-end price/cost effects (percent)
    136       76       128       143       83       113  
               
2008 Reserves Changes by Region
                                                                                                                 
    Crude Oil and Natural Gas Liquids (millions of barrels)     Natural Gas (billions of cubic feet)  
                                    Asia                                                     Asia                
            Canada/                     Pacific/                             Canada/                     Pacific/                
    United     South                     Middle     Russia/             United     South                     Middle     Russia/        
    States     America     Europe     Africa     East     Caspian     Total     States     America     Europe     Africa     East     Caspian     Total  
 
                                                                                                               
Revisions
    (13 )     94       51       (1 )     121       (20 )     232       (63 )     93       71       (55 )     (204 )     31       (127 )
Improved recovery
    8                                     8       1                                     1  
Extensions/discoveries
    5       1,168       4       64       56             1,297       229       17       16       12       419             693  
Purchases
                                                                                  -  
Sales
    (4 )     (2 )     (28 )                 (52 )     (86 )     (12 )     (17 )     (29 )                 (24 )     (82 )
         
Total additions before year-end price/cost effects
    (4 )     1,260       27       63       177       (72 )     1,451       155       93       58       (43 )     215       7       485  
Remove 2007 year-end price/cost effects
    (13 )     (69 )     (3 )     122       38       111       186       (43 )     (13 )     (313 )           776       103       510  
2008 year-end price/cost effects
    (105 )     (34 )     (6 )     133       105       81       174       (957 )     7       187             993       29       259  
Total additions
    (122 )     1,157       18       318       320       120       1,811       (845 )     87       (68 )     (43 )     1,984       139       1,254  
Production
    132       107       157       239       186       58       879       562       263       1,501       45       1,209       57       3,637  
Net change
    (254 )     1,050       (139 )     79       134       62       932       (1,407 )     (176 )     (1,569 )     (88 )     775       82       (2,383 )
         
Reserves replacement ratio, excluding sales (percent)
          1,179       35       26       95             175       30       42       6             18       54       16  
Reserves replacement ratio, including sales (percent)
          1,178       17       26       95             165       28       35       4             18       12       13  
Reserves replacement ratio, including sales and year-end price/cost effects (percent)
          1,081       11       133       172       207       206             33                   164       244       34  
         
 
See footnotes on page 69.


 


Table of Contents

   
EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
69
PROVED OIL AND GAS RESERVES REPLACEMENT(1)(2)(3) – Units are million barrels of oil or billion cubic feet of gas unless specified otherwise
                                                 
                                            Average  
    2008     2007     2006     2005     2004     2004-2008  
 
                                               
Non-U.S.
                                               
E&P costs (millions of dollars)
    14,095       11,227       12,111       10,442       8,683       11,312  
 
             
Oil reserves additions
    1,933       368       1,417       794       (246 )     853  
Oil production
    747       812       827       747       737       774  
 
             
Gas reserves additions
    2,099       2,685       5,319       8,145       7,626       5,175  
Gas production
    3,075       3,101       3,018       2,959       3,077       3,046  
 
             
Oil-equivalent reserves additions, excluding sales
    1,604       1,281       2,172       1,918       1,974       1,790  
Oil-equivalent reserves additions, including sales
    1,510       803       2,118       1,766       1,900       1,619  
Oil-equivalent reserves additions, including sales and price/cost effects
    2,283       815       2,303       2,151       1,025       1,716  
Oil-equivalent production
    1,259       1,329       1,330       1,240       1,250       1,282  
 
             
Reserves replacement ratio, excluding sales (percent)
    127       96       163       155       158       140  
Reserves replacement ratio, including sales (percent)
    120       60       159       142       152       126  
Reserves replacement ratio, including sales and year-end price/cost effects (percent)
    181       61       173       173       82       134  
Reserves replacement costs(4) (dollars per barrel)
    8.79       8.76       5.58       5.44       4.40       6.32  
               
 
                                               
United States
                                               
E&P costs (millions of dollars)
    3,473       2,299       2,274       1,992       1,828       2,373  
 
             
Oil reserves additions
    (122 )     91       (102 )     (299 )     (24 )     (91 )
Oil production
    132       141       149       170       198       158  
 
             
Gas reserves additions
    (845 )     1,767       (930 )     2,134       1,903       806  
Gas production
    562       649       718       775       859       713  
 
             
Oil-equivalent reserves additions, excluding sales
    28       800       (117 )     73       14       159  
Oil-equivalent reserves additions, including sales
    22       788       (167 )     (40 )     (123 )     96  
Oil-equivalent reserves additions, including sales and year-end price/cost effects
    (263 )     386       (257 )     57       293       43  
Oil-equivalent production
    226       249       268       299       341       276  
 
             
Reserves replacement ratio, excluding sales (percent)
    12       321             24       4       58  
Reserves replacement ratio, including sales (percent)
    10       316                         35  
Reserves replacement ratio, including sales and year-end price/cost effects (percent)
          155             19       86       16  
Reserves replacement costs(4) (dollars per barrel)
    124.04       2.87             27.29       130.57       14.92  
               
 
                                               
Worldwide
                                               
E&P costs (millions of dollars)
    17,568       13,526       14,385       12,434       10,511       13,685  
 
             
Oil reserves additions
    1,811       459       1,315       495       (270 )     762  
Oil production
    879       953       976       917       935       932  
 
             
Gas reserves additions
    1,254       4,452       4,389       10,279       9,529       5,981  
Gas production
    3,637       3,750       3,736       3,734       3,936       3,759  
 
             
Oil-equivalent reserves additions, excluding sales
    1,632       2,081       2,055       1,991       1,988       1,949  
Oil-equivalent reserves additions, including sales
    1,532       1,591       1,951       1,726       1,777       1,715  
Oil-equivalent reserves additions, including sales and price/cost effects
    2,020       1,201       2,046       2,208       1,318       1,759  
Oil-equivalent production
    1,485       1,578       1,598       1,539       1,591       1,558  
 
             
Reserves replacement ratio, excluding sales (percent)
    110       132       129       129       125       125  
Reserves replacement ratio, including sales (percent)
    103       101       122       112       112       110  
Reserves replacement ratio, including sales and year-end price/cost effects (percent)
    136       76       128       143       83       113  
Reserves replacement costs(4) (dollars per barrel)
    10.76       6.50       7.00       6.25       5.29       7.02  
               
 
(1)   The data shown above and on the preceding page include reserves, production, and costs from non-consolidated interests and Canadian oil sands operations. This is a more complete summary of ExxonMobil’s exploration and production operations than the data in Appendix A of ExxonMobil’s 2009 Proxy Statement, which due to financial reporting requirements, treat Canadian oil sands as a mining operation.
 
(2)   See Frequently Used Terms on pages 96 through 99.
 
(3)   The term “sales” includes the impact of expropriation of proved reserves in Venezuela (462 million oil-equivalent barrels) in 2007.
 
(4)   Calculation based on exploration and production costs divided by oil-equivalent reserves additions. All values exclude the impact of asset sales; i.e., reserves sold and proceeds received; and price/cost related effects associated with using December 31 prices and costs.

 


Table of Contents

   
70
EXXON MOBIL CORPORATION 2008 FINANCIAL & OPERATING REVIEW
 OIL AND GAS EXPLORATION AND PRODUCTION EARNINGS
The revenue, cost, and earnings data are shown both on a total dollar and a unit basis, and are inclusive of non-consolidated and Canadian oil sands operations. They are not directly comparable to the data in Appendix A of ExxonMobil’s 2009 Proxy Statement, which due to financial reporting requirements, treat Canadian oil sands as a mining operation. The data displayed here provide a more complete summary of ExxonMobil’s exploration and production operations.
                                                                                         
    Total Revenues and Costs, Including Non-Consolidated Interests and Oil Sands     Revenues and Costs per Unit of Sales or Production(1)  
                                    Asia                                            
            Canada/                     Pacific/                             Canada/              
    United     South                     Middle     Russia/             United     South     Outside        
    States     America     Europe     Africa     East     Caspian     Total     States     America     Americas     Worldwide  
             
2008   (millions of dollars)
  (dollars per unit of sales)
 
Revenue
                                                                                       
Crude oil and NGL
    11,788       8,540       13,910       20,606       17,095       5,304       77,243       87.95       81.43       91.66       89.84  
Natural gas
    3,296       1,834       15,230       39       7,327       67       27,793       7.23       7.82       8.59       8.35  
             
    (dollars per barrel of net oil-equivalent production)
 
Total revenue
    15,084       10,374       29,140       20,645       24,422       5,371       105,036       71.73       71.23       73.74       73.19  
Less costs:
                                                                                       
Production costs excluding taxes
    2,675       2,625       3,051       1,603       1,267       457       11,678       12.72       18.03       5.91       8.14  
Depreciation and depletion
    1,427       1,043       2,662       2,471       906       504       9,013       6.79       7.16       6.06       6.28  
Exploration expenses
    189       251       183       439       341       60       1,463       0.90       1.72       0.95       1.02  
Taxes other than income
    2,021       81       4,248       1,815       6,017       105       14,287       9.61       0.55       11.29       9.95  
Related income tax
    3,191