Exhibit 99.1

Exxon Mobil Corporation

Presentations and Q&A Session

Analyst Meeting

New York, NY

March 9, 2011

David Rosenthal (Vice President of Investor Relations and Secretary of the Corporation)

Good morning. For those of you I have not yet met, I’m David Rosenthal. I’m the Vice President of Investor Relations and Secretary of ExxonMobil, and I’d like to welcome you to the 2011 ExxonMobil Analyst Meeting. But before we begin, I would like to familiarize everyone with the safety procedures here at the New York Stock Exchange.

There is an exit in the back of the room and one through the doors on my right. In the event of an emergency, New York Stock Exchange personnel will provide us with instructions on how to respond. They will also, in the case of an evacuation, direct us to the nearest exit. So please wait for instructions if this were to occur.

I would also like to ask everyone at this time to please ensure that your cell phones and BlackBerries are turned completely off.

Next, I would like to draw your attention to the cautionary statement that you will find in the front of your presentation manual. This statement contains information regarding today’s presentation and discussion. If you have not previously read this statement, I would ask that you do so at this time. I would also refer you to our website, ExxonMobil.com for additional information on factors affecting future results as well as supplemental information defining key terms that we will use today.

Our review today will begin with Rex Tillerson discussing some of the key factors influencing the industry and business environment followed by a look at our financial and operating results and the competitive advantages which led to such strong performance across our business.

Mark Albers will then provide an update on our global exploration program and major upstream projects. Andy Swiger will follow with a discussion on our unconventional portfolio including the integration of XTO. Rex will then have some summary remarks after which we will take a short break. Following the break, we will conduct a question and answer session, and the meeting will end by noon.

It is now my pleasure to introduce our Chairman and CEO, Rex Tillerson. Rex.

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Rex Tillerson (Chairman and CEO)

Well thank you, David. Good morning, all. It’s always nice to visit New York City, and it’s always a real pleasure to be here at the stock exchange. The folks here at the stock exchange really take good care of us when we hold these events, and I want to thank them for that as we use up some of their space today.

Also, I want to welcome all of you who’ve joined us for this year’s 2011 Analyst Meeting, those of you, certainly, here in person but I also want to welcome those who are following the meeting either by telephone or on the webcast.

Today I am pleased to share our 2010 financial and operating results and discuss the competitive advantages that position ExxonMobil to continue delivering value to our shareholders over the long term. Our competitive advantages grounded in our commitment to integrity, risk management and financial discipline continue to distinguish ExxonMobil. As a result, we remain well-positioned for the challenges and opportunities in the current and the long-term business environment.

Before getting to the details of our financial and operating results and a look at some of our plans, providing some context for all of this, I think, will be useful to you and others and to help you understand the future as we see it and how our plans fit in.

The global economy appears to be stabilizing with signs of modest growth in the United States, stability in Europe and continued robust growth in the developing world, especially in the Asia-Pacific region. Countries around the world are striving for prosperity while seeking to implement an appropriate level of regulation and oversight that will support sustainable long-term economic growth.

In the context of these economic conditions, government policies that will influence climate change continue to be developed. However, practical solutions in this regard remain uncertain. We have also observed some of our competitors in the reevaluation of their business models and plans. This includes publicly disclosed corporate reorganizations, a move away from the integrated business model and even new strategies for some.

In my view, ExxonMobil stands apart from our competitors. While the business environment presents an ever-changing set of challenges, it also presents opportunities. ExxonMobil remains well-positioned to meet long-term global energy and petrochemical demand which is forecast to be robust.

Over the period to the year 2030, we anticipate expanding prosperity for a growing world population to drive an increase in global energy demand of about 35% when compared to a baseline year of 2005. To meet these growing needs and ensure reliable and affordable energy,

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we must pursue a diverse mix of commercially viable energy sources. This is not the time to slow down investment activity or technological development.

The bar chart on the left shows projected demand growth from 2005 to 2030 by energy type. In 2005, oil, natural gas and coal provided approximately 80% of the world’s energy. Nuclear, hydroelectric, geothermal, biomass, along with wind, solar and biofuels contributed the balance. If we look to the year 2030, the global energy mix will continue to evolve. Natural gas will be the fastest growing major energy source and will overtake coal as the second largest global energy source behind oil.

Growth of this reliable, affordable and clean fuel is aided by technologies that have unlocked vast new supplies to meet a wide variety of needs, perhaps most notably for power generation. We do expect the evolving policies in developed countries to reduce greenhouse gas emissions. As an abundant and less carbon-intensive fuel, natural gas is well suited to support that objective.

Importantly, this outlook anticipates that energy efficiency, long an important element in modulating energy supply demand growth, will play an increasing role in moderating future demand throughout the world. The bar on the right shows that the energy saved through projected efficiency gains is expected to be about twice the projected growth in global energy consumption. Without these efficiency gains, total energy demand will be much higher in the year 2030.

As mentioned on the previous slide, natural gas is expected to be the fastest growing major fuel source, increasing about 60% globally by the year 2030. On the left is depicted our natural gas outlook for the United States. We expect U.S. domestic gas production to increase with declines in conventional production being more than offset by increases in unconventional gas production.

The chart in the middle of the slide depicts the gas outlook for Europe. With domestic production falling, Europe will meet its demand growth with a combination of imports via pipelines from Russia, the Caspian region and North Africa as well as imports of LNG.

Finally, the chart on the right describes the Asia-Pacific region, where demand in 2030 will be approaching three times the level of 2005. This rising demand will be met by growth in local conventional and unconventional supplies, as well as increasing LNG and pipeline imports.

ExxonMobil is favorably positioned in each of these markets with our diverse global gas portfolio of high-quality operations and advantaged projects.

In addition to increases in natural gas demand, we also expect long-term growth in the transportation energy demand. By 2030, we expect energy demand for the transportation sector to increase almost 40% versus 2005. The increase is driven by growth in the non-OECD, or developing countries, where demand is expected to double as a result of rising economic

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prosperity. OECD demand is projected to be essentially flat reflecting significant efficiency gains.

Despite the potential positive effects of demand growth on the downstream industry, we expect a very challenging business environment. This view reflects a global increase in industry refining capacity and ongoing potential for expansion of regulatory-related policies and mandates.

Integration across ExxonMobil’s businesses is a significant competitive advantage and will continue to help us mitigate the impact of some of these challenges. In both high and low margin periods, we remain focused on maximizing the benefits of integration.

Let’s now take a look at the petrochemical environment. Global demand for commodity chemicals is poised to resume growth. The graph shows year-on-year growth of global GDP in blue and global demand for our key chemical commodities in red. The bold trend lines show that historically the demand for chemical commodities has grown about two to three percentage points above GDP. And even after the steep decline in 2008, we expect demand to remain about two percentage points above GDP.

The demand for these products increases more than the base economic growth due to ongoing substitution of materials as products such as plastics and synthetic rubber replace traditional materials such as wood, paper and aluminum.

In addition, these products support end uses with high growth rates in new markets, especially as the standard of living improves in the developing world. Therefore, most of the growth will be in the Asia-Pacific region while demand in developed regions is still expected to grow in line with GDP.

Specialty products offer higher value properties that can accelerate substitution rates and thus have the potential for demand growth rates that are even higher than the commodities.

This strong global demand for energy and related products presents important challenges. In the decades ahead, the world will need to expand supplies in a way that is safe, secure, affordable and environmentally responsible.

The scale of the challenge is enormous and requires an integrated set of solutions and the pursuit of all economic options. A commitment to the development of new energy technologies to expand supply of traditional fuels and advance new energy resources will require unprecedented levels of investment. Sound, stable government policies are an important factor in enabling this level of capital investment.

We also know from experience that the best way to achieve our shared goals is by effectively managing and addressing the risk inherent to our business and by maintaining a relentless focus on operational excellence.

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Risk management is not only about preventing and mitigating negative impacts but it is also about achieving and maximizing positive outcomes for investors, stakeholders and consumers. The industry faces multiple uncertainties and inherent risk. First and foremost are risks associated with safety, security, health and environment. Over the years, the industry has seen examples where the failure to effectively mitigate these risks have resulted in serious, even tragic consequences, including the loss of life and harm to the environment.

Additionally, there are significant financial, economic and commercial risks associated with the very large and growing capital investments required to develop increasingly complex oil and gas projects. The recovery of resources located miles beneath the surface of the earth also carries a wide range of technical risk involving many geological and engineering complexities. Given that these projects are executed in many countries across the world and often operate for several decades, there’s the associated geopolitical risk as governments and political priorities change often within the lifecycle of one project.

Finally, the industry is faced with risk of climate change and the resulting effect of government policies and impact on global markets. Well-developed processes, procedures and people are required to manage these risks. Over many decades, ExxonMobil has established common, worldwide expectations for addressing the risk inherent in our business. These expectations are fully embedded in our culture, and we remain focused on continuously improving our ability to effectively identify and manage risk across the business.

First, a capable, committed workforce with clear accountability is important since human decision making is a significant component of successful risk management. Our goal is to develop our employees to have the highest technical and leadership skills in the industry which creates a sustainable source of competitive advantage. This is supported by well-developed and clearly defined policies and procedures to ensure that we have a structured globally consistent approach with the highest standards in place. These high standards are rigorously applied at the design stage to reduce and eliminate risk where possible.

Additionally, employee and contractor training is an essential element to ensure support at all levels within the organization and to embed the right behaviors. We also employ a systematic approach to measuring performance and seeking continuous improvement across our business. This is all done within the context of rigorously applied management systems.

ExxonMobil utilizes a comprehensive set of systems to manage the many risks we face. Recognized as a model of success in the industry, ExxonMobil developed the Operations Integrity Management System, or OIMS, to provide a robust framework for managing safety, security, health and environmental risk. OIMS is used in our facilities worldwide and enables us to measure progress, ensure management accountability for results, and establishes common worldwide expectations for controlling operational risk.

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Facility integrity management systems are employed to prevent high-impact equipment and facility failures and to improve equipment reliability. The benefits are significant and have resulted in material reductions in unscheduled downtime.

The Controls Integrity Management System, or CIMS, provides a structured, common process for conducting business in a well-controlled manner. This includes establishing effective controls, monitoring and enforcing compliance continuously, and resolving control weaknesses in a timely manner.

ExxonMobil’s Capital Project Management System, EMCAPS, uses management gate reviews and checkpoints to ensure that projects are conducted in a safe and environmentally responsible manner, deliver assets of appropriate quality, meet costs and schedule expectations, and achieve commercial success.

We have additional management systems that we employ to mitigate the many risks we face, including the oversight of assets that are operated by others. We believe that the frameworks in place at ExxonMobil provide a unique, competitive advantage and serve as the foundation for strong financial and operating results. And 2010 was no exception.

We measure our performance using a variety of financial and non-financial parameters. Overall, I’m pleased with our 2010 performance across all key measures and business lines. First and foremost, we had a solid year of operational excellence including industry-leading safety performance and strong environmental management.

We also delivered exceptional financial and operating results. These results reflect the strength of our proven business model which has enabled us to consistently produce strong returns for our shareholders, including unmatched distributions. We continue to invest with discipline, focusing on creating long-term value while maintaining a perspective that transcends year-to-year economic conditions.

Let’s begin with a review of our safety and environmental performance. As many of you have heard me say before, nothing receives more management attention at ExxonMobil than the safety and health of our employees, our contractors and our customers and the people who live and work in the areas where we operate. Our vision that Nobody Gets Hurt is internalized in the Company’s culture and is a central, critical element of daily operational excellence. Our safety performance continues to lead the industry, and we are proud of this achievement.

In 2010, we achieved our best-ever lost time incident rates for our combined employee and contractor workforce, improving upon our record performance of 2009. Our strong safety performance is the direct result of effective risk management and a relentless focus on operational excellence. Within ExxonMobil, we know good safety performance leads to good business performance. We also know that a safety culture has a positive influence on the behavior of each employee and contractor.

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Safety is a core value at ExxonMobil that influences decision making at all times and at every level of the organization. At ExxonMobil, we pursue excellence in safety performance using a systematic, proactive and globally aligned approach. We are dedicated to the highest standards of safety and health, and remain committed to maintaining and improving upon these already high levels of performance. To do so requires diligence and innovation. An organization cannot become complacent or content with their past safety performance, and we are determined not to be satisfied until we can conclude each day when Nobody Gets Hurt.

Let’s now look at our environmental performance. Meeting the world’s growing need for energy while minimizing impacts on the environment is one of our biggest challenges. At ExxonMobil we have implemented rigorous environmental management programs that deliver ongoing improvement in our global environmental performance. The results of this discipline are significant, particularly in the area of energy efficiency. By applying our Global Energy Management System we’re on track to meet targets for improving energy efficiency across our worldwide refining and petrochemical operations by at least 10% between the years 2002 and 2012.

We also continue to progress initiatives to reduce the hydrocarbon flaring associated with our operations. In 2010, upstream hydrocarbon flaring was over 20% lower than in 2009, and was down almost 60% from levels only a few years ago. Through flare reduction and energy efficiency steps taken since 2006, we have reduced greenhouse gas emissions by 11 million metric tons, which is equivalent to taking 2.2 million cars off the road in the United States.

Ongoing improvement efforts in our marine organizations resulted in zero hydrocarbon spills from both company owned and operated vessels and term chartered vessels in 2010. We also reduced the number of spills not from marine vessels, achieving our best ever results. In our current operations and as we develop projects for the future, we will continue working to Protect Tomorrow. Today.

Let’s now take a look at our 2010 financial and operating results. ExxonMobil earned $30.5 billion in 2010, an increase of 57% over 2009. These results led the industry, including a record year for our Chemical business. This performance reflects several project startups and excellent operational performance across our portfolio. With this relentless focus on operational excellence delivering strong reliability, we continue to maximize the value of our asset base.

To give these results further context, let’s look closer at our Upstream financial and operating performance relative to competition. This chart shows Upstream earnings per oil-equivalent barrel produced. Our high-quality portfolio of upstream assets continues to deliver strong results. ExxonMobil’s average earnings per barrel from 2006 to 2010 or over the last five years were over $17 a barrel, which was ahead of our competition.

As we expected, our 2010 unit per barrel earnings of about $15 a barrel were somewhat depressed by the inclusion of XTO. Underlying profitability continued to benefit from the strength of our balanced portfolio and disciplined approach to cost management. We continually

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seek to maximize the value of each oil-equivalent barrel while growing the amount of volumes we produce.

Upstream volumes grew an impressive 13% in 2010, driven by superior organic growth of 6% from project startups and strong operational performance across the Upstream portfolio. The ongoing successful integration of XTO’s world-class unconventional operations added another 7%.

As the largest non-government-owned producer of oil and gas with volumes of 4.5 million oil-equivalent barrels produced per day, these increases were the most significant among our competitors and exceeded the competitor average by 12 percentage points. Effective risk management and a focus on operational excellence serve as the foundation for this strong performance.

Our ability to replace more reserves than we produce at attractive unit cost positions us to continue to deliver profitable volume growth in the future. The chart on the left shows the average reserves replacement ratio and replacement cost for the five-year period 2005 to 2009. We continued to replace more than our annual production at unit costs below those of our major competitors. ExxonMobil’s average reserve replacement unit cost across this period was $8 per oil-equivalent barrel, which was about $5 below the competitor average. In 2010 we replaced 211% of reserves produced excluding the impact of asset sales, representing the 17th consecutive year in which we have replaced more reserves than we produced. Our proven reserves now equal 24.8 billion oil-equivalent barrels, an increase of 8% from 2009.

We continue to view return on average capital employed as the best measure of capital productivity. In 2010, ExxonMobil’s ROCE was an industry-leading 22%, more than four percentage points higher than the nearest competitor. Over the five-year period of 2006 to 2010, our ROCE averaged above 27%, over seven percentage points higher than the nearest competitor.

We manage each of our business lines for the long term, consistently executing our business model across the Upstream, Downstream and Chemical segments. As a result, our ROCE remains ahead of competition, reflecting the strength of our integrated portfolio.

We have a proven record of responsible stewardship of our shareholders’ money as evidenced by our disciplined approach to investing through the business cycle and the absence of any material asset impairments. In this regard, we’re unique in our industry. From 2005 to 2009, asset impairments by many of the companies within the oil and gas industry totaled $96 billion. The result is an erosion of shareholder value and a distortion of returns.

During this same timeframe, ExxonMobil had no material impairments of assets. Not only does this demonstrate the strength and quality of our portfolio, it highlights an efficient use of capital and an ability to capture value from each dollar we invest. As a result, we are able to generate superior cash flow, resulting in unmatched financial strength and flexibility.

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In 2010, cash flow from operations and asset sales was approximately $52 billion, an increase of over 70% from 2009. Our cash balance at year-end 2010 was over $8 billion. Strong cash flows funded all attractive investment opportunities at record levels in 2010 and allowed us to pay a growing dividend, as well as return additional cash to shareholders with share purchases.

To reduce our debt levels, we also deployed cash to reduce debt by more than 25% in the six months following the closing of the XTO merger, effectively retiring about 60% of the debt we assumed as a result of that merger. Cash generation last year allowed us to maintain a level of shareholder distributions that is unmatched in the industry.

We maintained our approach to dividends with a view to build long-term shareholder value and provide reliable dividend growth through not just the ups, but also the downs of the business cycle. Over the past five years, we distributed almost $40 billion in dividends to shareholders. During this same period, we increased per share dividends 53%. Since 1983 through multiple business cycle expansions and contractions, shareholders have received annual per share dividend increases at an annualized growth rate of 5.7%, almost twice the rate of inflation.

In addition to growing dividends, we have provided added flexibility in returns to shareholders via share repurchases. In 2010, we distributed over $11 billion to shareholders through share purchases, while competitor programs were curtailed for much if not all of the year. On a cumulative basis, distributions to shareholders through share purchases were $114 billion over the last five years, more than twice the total distributed by our competitors.

Purchases have reduced shares outstanding by almost 19% since the beginning of the year 2006 and that includes the impact of the shares issued for the XTO merger. This results in an average annual yield of 5.6%. We continue to believe the share purchase program is an effective way to distribute value to shareholders while at the same time maintain the flexibility to balance the cash needs of the corporation.

ExxonMobil’s shareholder distributions have provided an average total yield of 7.6% since the beginning of 2006, which exceeds the competitor average of 6% and exceeded the average yield of each competitor in the group. We are committed to return excess cash to shareholders while ensuring attractive investment opportunities are fully funded for the future.

In 2010, we invested $32 billion in capital and exploration expenditures that positioned the business for long-term growth and sustainability. Over the past five years, we have invested over $126 billion sustaining our pursuit of attractive opportunities throughout the business cycle. We pursue opportunities in all regions of the world and across all business lines. In 2010, we completed three major upstream projects with 2011 forecast production contributions of 120,000 barrels equivalent per day.

Our approach to investing is to advance all attractive opportunities that will provide acceptable returns across a broad range of industry and market conditions, while maintaining our focus on

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capital efficiency and our discipline. I will comment on our future CapEx plans later, but for now, let’s look at another example of managing capital: maintaining an active portfolio management program.

ExxonMobil has a longstanding practice of continually reviewing all assets for their contributions to the Company’s operational and financial objectives. This is not a new program for us. The Company markets assets that, for a variety of reasons, may be of more value to others. This approach is fundamental in our business model.

As such, we have ongoing and active asset management activities through the business cycle to capture the best value. In fact, since the Exxon and Mobil merger, we have generated almost $40 billion in cash flow and $11 billion in earnings from targeted divestments across all of our business lines. In doing so, we divested approximately 4 billion oil-equivalent barrels or 5% of our resource base and over 200,000 barrels per day of refining capacity, while retaining assets which hold long-term value.

Again, I am very pleased with our 2010 performance across all the key measures and all the business lines. The results reflect the strength of our business model and the application of that model across all three of our business lines. I’ll now discuss the Upstream, Downstream and Chemical business segments.

ExxonMobil has established competitive advantages that are evident across all three of these business lines. These competitive advantages set us apart and have not only led to superior performance, but also serve as the foundation for ongoing success. Within each of our businesses the quality, size and diversity of our balanced portfolio of resources, projects, products and assets is unparalleled.

Our focus on discipline, selective investment from initial resource capture, through project development, through ongoing operations, underpins our ability to deliver superior returns. As we invest in the business and run our operations, we employ high-impact technologies to ensure we maximize resource value. We have an ongoing effort to identify and develop new technologies that enable us to be more efficient and more effective.

With an unyielding focus on operational excellence, we develop and deploy systems that provide consistent application of the highest operational standards. And finally, we capture substantial value across the Company through the global integration of our business lines and organization. Within this model, we have implemented processes and systems that enable our organization and investments to capture the highest value for each molecule we produce or process.

I’ll now review specific examples of these competitive advantages in each business line, starting first with the Upstream and the quality of our balanced portfolio. At over 84 billion oil-equivalent barrels, ExxonMobil has the largest publicly reported resource base among international oil companies. We increased the resource base by nearly 10 billion oil-equivalent

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barrels in 2010. The depth and diversity of the resource base offers flexibility and supports a significant upstream project portfolio.

The chart on the left shows the resource base, characterized by type, as an indication of the breadth of technology approaches that are necessary to bring these resources to production. The largest single component remains conventional oil and gas, followed by heavy oil, which includes both in-situ and oil mining processes. Our position in unconventional gas and oil is also substantial as a result of the addition of XTO. The remainder is made up of resources with high content levels of acid and sour components, liquefied natural gas, Arctic resources and resources located in deepwater.

In terms of geographic distribution, just over 50% of our resource base is located in the Americas with the remainder distributed around the world. The resource base is also evenly balanced between liquids and natural gas. The uniqueness of our resource base is found in the underlying scale and quality which provides ExxonMobil with strategic flexibility in our upstream investment options.

Now, we’ll look more closely at our global gas position. ExxonMobil’s gas portfolio includes 79 trillion cubic feet of proved reserves spanning all resource types, major markets and commercial structures. The chart on the upper left illustrates our global gas resource base by resource type, which includes a sizeable position in conventional gas, shale gas, LNG and tight gas. In fact, we hold a leading position in unconventional gas with significant growth potential.

On the upper right, we show the major markets where our natural gas is sold. The primary markets include Europe, Asia and the Americas. The lower chart shows a projection of anticipated 2011 gas sales by contract type, which as you can see provides us with flexibility and market optionality. The proportion of oil-indexed contracts is significant, as shown in more detail on the next slide.

ExxonMobil holds a wide range of gas contracts which provides flexibility to maximize the value of our strong global gas position. The chart on the left shows 2010 oil and gas production, with a mix of approximately 54% oil and 46% gas. As the bar on the right illustrates, significant volumes of gas was sold under contracts that include a relationship to oil prices. Including these, approximately 70% of total production was linked to oil pricing, including one-third of our gas volumes.

A number of our flexible contracts provide the ability to divert gas production to the most attractive markets. Together, advantaged developments and diverse contract structures serve to further reduce market risk while delivering greater shareholder value. In addition to a strong resource base, we have an attractive suite of new growth opportunities.

We have a diverse portfolio of high-quality opportunities across resource types and geographies. Illustrated on this chart, the portfolio includes new play tests, shown in yellow, pursuits in established basins in green, and unconventional resource opportunities in red. The result is a

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balance between risk and resource exposure. Mark Albers will provide additional details on our exploration program shortly.

For now, I’ll turn to our Downstream. ExxonMobil is the largest global integrated refiner, and our refineries are, on average, 60% larger than industry. This size difference provides us with a scale advantage versus competition. We’re also the largest manufacturer of lubricant basestocks as well as a leading marketer of petroleum products.

Our refineries are among the most efficient in their geographies as a result of constant focus on energy and cost efficiencies, circuit optimization and reliable operations. We also capture significant value by running challenged crudes, which are typically discounted in the market, allowing us to reduce feedstock cost and increase margins. Enabled by our Virtual Molecular assays, capital investments to expand feed flexibility and proprietary technology advantages, we are an industry leader, processing over 60% more challenged crudes than the industry average.

Our world-class brands provide another example of the quality of our Downstream. This graph shows the broad spectrum of sales channels for our Fuels Marketing business and represents about 3.7 million barrels per day in total sales. Our branded retail business is well known, with transportation and fuel products sold through Exxon, Mobil, and Esso brands.

The business-to-business portion of our portfolio, which includes industrial and wholesale, marine and aviation is also a significant contributor. Business-to-business makes up over 50% of total Fuels Marketing sales while employing a very low capital base.

The Fuels Marketing business has diverse channels that provide secure, ratable and profitable outlets that are highly integrated with our refineries. In addition, our global lubricant brands have significant customer appeal and are recommended by numerous original equipment manufacturers. Our high-quality products, coupled with a strong refining and distribution network, position us as a sought after and reliable supplier to a wide variety of customers around the world. The quality of our world-class brands has contributed to profitable sales growth.

In the high-value finished lubricant business, we’ve achieved considerable sales growth due to a focus on synthetic oils, including our flagship passenger vehicle engine oil, Mobil 1. We continue to grow this brand, which strengthens our market-leading position. In fact, Mobil 1 set another sales record in 2010. The graph to the left illustrates synthetic sales growth since 2005. Through technology and brand leadership, we have captured significantly higher sales growth than the industry.

The Mobil SHC brand of synthetic industrial oils has also seen significant growth in recent years, as customers are choosing to protect their equipment and to increase productivity by using our differentiated products and lubrication engineering services. By leveraging equipment builder relationships and efficient global business models, we have grown our business in developing markets, such as China, India and Russia at rates considerably faster than the industry. The

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strength of our brands and technology, coupled with a reliable and efficient supply chain, will enable us to capture superior growth in the future.

Now, let’s take a closer look at the Chemical portfolio. Our unique Chemical portfolio captures benefits of scale in commodities, while maximizing value from specialties. Our world-scale commodity businesses, shown in red, capture upside earnings when energy margins are strong. Specialties, shown in blue, provide a stable yet growing earnings base that delivered a record $1.8 billion, contributing to a record almost $5 billion in total Chemical earnings in 2010. Specialty products benefit significantly from a lower-cost structure when they are produced at the same integrated sites as our commodities.

Our diverse product portfolio is backed by proprietary technology in areas such as advantaged feedstocks, lower-cost manufacturing, and premium products. The ability to consistently deliver strong results from commodities and specialties positions ExxonMobil Chemical to outperform competition, and they do.

We are well-positioned to meet growing chemical demand in the Asia-Pacific region. As you can see on the chart, we lead our key competitors in both existing and announced manufacturing capacity in Asia-Pacific and the Middle East.

For example, our integrated joint venture in Fujian Province, China, started up in late 2009. The major expansion under way at our integrated Singapore complex will increase our advantaged supply position for both commodity and specialty products. And I’ll say more about this project later. We’re also progressing a project at our joint venture in Saudi Arabia to develop specialty products for the automotive industry.

We’ll now look at the competitive advantages that are generated through our disciplined investing. ExxonMobil has an extensive portfolio of over 130 active major upstream projects. This chart shows the portfolio distribution by project type. Our large project inventory, which will develop 26 billion net oil-equivalent barrels, spans all project types and geographies. Our experienced global project execution team applies industry-leading project management capabilities in developing these resources via a disciplined, gated process from planning to startup. Application of fit-for-purpose technology ensures we advance projects with the lowest unit development cost to maximize the value of the resource.

Next, we’ll look at some of the projects we expect to start up in the near term. This slide shows eight of the 11 major projects that we plan to start up in 2013. Later this year, Pazflor and the Angola Deepwater will start up. During the years 2012 to ‘13, 10 projects are expected to come online, including two projects in Angola, three in Nigeria, one oil sands project in Canada, the first phase of the Kashagan development in Kazakhstan and the Kipper Tuna Turrum project in Australia. These projects provide ExxonMobil with a strong foundation for future production growth.

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This chart shows the projected increase in net production from project startups over the next several years. As previously stated, in 2011 we will deliver 120,000 net oil-equivalent barrels per day from the 2010 project startups. Combined with other projects in our near-term portfolio, we anticipate adding nearly 1.4 million net oil-equivalent barrels per day by the year 2016. As shown on the chart in the blue shading, 80% of these new additions are oil volumes, many of which will contribute to a similar buildup in long-plateau volumes.

Our Downstream business has invested over $1 billion to increase the supply of ultra-low sulfur diesel in support of forecasted long-term demand growth. In 2010, we completed facilities at refineries in the United States and Europe to increase the supply of ultra-low sulfur diesel by more than 6 million gallons per day. Additional projects are under way, including new facilities to provide low sulfur motor fuels at our Sriracha, Thailand refinery and ultra-low sulfur diesel at our Singapore refinery. Disciplined investing contributes to our position as the most capital efficient Downstream business, relative to the industry.

As this graph shows, we have reduced Downstream capital employed consistently since 2000, while the downstream capital employed of our key competitors has increased. In 2010, ExxonMobil’s Downstream operated with nearly one-half the capital employed of the competitor average, yet generated nearly 40% more earnings. In addition to disciplined capital investments, we constantly evaluate opportunities to monetize our asset base.

In fact, since 2000, we divested our interest in 11 refineries, over 5,000 miles of pipelines and about 140 product terminals. We also had a net reduction of about 40 lube oil blend plants and 20,000 retail sites. Continuously rationalizing our holdings for optimum shareholder value is not something new for us. Our approach to disciplined investing includes taking advantage of the most attractive markets. A good example of this is found in our Chemicals business.

A major expansion at our Singapore site to meet demand growth in the Asia-Pacific region will add shareholder value and build on the key competitive advantages we already have. The project is past its peak construction, and we anticipate mechanical completion and startup of various units to occur in phases during 2011.

With the expansion, we are adding a significant amount of new finished product capacity of over 2.5 million metric tons per year. Underpinned by proprietary technologies, this advantaged project will have substantial feed flexibility and world scale efficiency. In addition, we are initiating production of several of our premium products in Asia-Pacific. When the project is complete, Singapore will be our largest integrated site in the world.

Similar to our Downstream business, ExxonMobil Chemical is the most capital efficient among its competitors. Dow, BASF and ExxonMobil all have similarly sized businesses in terms of revenue. This chart shows our capital employed versus the capital employed of Dow and BASF. Our use of capital remains very efficient as a result of a long track record of very disciplined investments. Our engineering and strong project execution also ensures that we keep capital costs

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low by leveraging best practices. Most importantly, our growth has come primarily through the application of proprietary technology, rather than acquisitions.

As I have already referenced, high-impact technologies deliver significant value across each business line, starting first with the Upstream. Our long-term commitment to research continues to deliver advantaged technologies. For example, our high-end seismic processing has led to better representations of the subsurface, and we’re using new seismic technologies to detect features that control flow in reservoirs.

In drilling, we’re developing methods to keep boreholes clean, stable and serviceable by removing cuttings faster and more efficiently. This research, combined with results from our FastDrill technology and management of drill string vibration, further increase drilling speed and reach. In many carbonate reservoirs, we stimulate flow by creating long, highly conductive conduits called wormholes. Laboratory experiments and computer modeling are showing us how these wormholes grow, connect the reservoir to the well to promote flow and ultimate recovery.

We’re also integrating a wide variety of technologies with XTO’s data and knowledge to enhance shale gas production. These include new fracturing techniques, seismic and well-log methods, and imaging of shale pore networks in 3D, using a state-of-the-art electron microscope. In addition, we have commenced field testing of our one-step cryogenic method for processing gas streams with high CO2, H2S and other inerts at our new commercial scale demonstration plant at LaBarge, Wyoming. Implementation of this Controlled Freeze Zone technology is an important step toward cost effective, safe and environmentally responsible removal of carbon dioxide and hydrogen sulfide from natural gas streams.

Now, I’d like to showcase one example of the benefits generated from our long-term commitment to research and development by looking at Abu Dhabi’s giant offshore Upper Zakum field. ExxonMobil is working as part of the ZADCO operating company to develop this field’s extensive oil resources through an innovative approach, the creation of artificial islands where drilling rigs and processing facilities are co-located. With our partners, we developed a plan for the creation of three of these islands, which are now under construction.

ExxonMobil also created a technology center in Abu Dhabi in 2007 to facilitate collaboration and innovation. A key element of the development plan is the deployment of technology solutions that integrate our advanced extended reach drilling technologies and completion design capabilities. The use of extended reach drilling technology at Upper Zakum recently demonstrated the feasibility of this island development concept. This innovative approach has enabled us to capture several billions of dollars of savings in the project, and increase the ultimate recovery from the reservoir, as well as dramatically reduce the environmental footprint.

ExxonMobil has a rich legacy of Downstream technology leadership, with many technological “firsts”. Our scientists and engineers developed and patented many of today’s core refining processes and developed the world’s first synthetic lubricant. Today, we employ fundamental models of hydrocarbon composition that enable us to understand how each molecule can be best

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utilized to produce the highest value product. Combining these models with state-of-the-art techniques further enables development of advanced catalyst and processes to efficiently upgrade a wide variety of crudes into clean burning fuels.

We are also developing proprietary heavy oil characterization technology that will allow us to more effectively process heavier feeds, and a variety of technology programs are underway to manage energy consumption and improve efficiency. We deploy technology solutions across the entire supply and production chain. Our advanced modeling and characterization tools enable challenging new feeds to be selected for processing. We use unique supply chain optimization models to guide feedstock routing. In addition, technology aids in developing advanced fuel and lubricant products.

Through constant discovery, we are able to develop and deploy proprietary technologies that provide near-term and long-term competitive advantages to our businesses, including the development of next generation technologies.

We are working in partnership with Synthetic Genomics Incorporated in a development of advanced algae-based biofuels. We believe there are numerous potential benefits of biofuel production from algae that make this option a more attractive choice over other biofuels. Through the natural process of photosynthesis, algae consume carbon dioxide and convert it to useful products like oils and oxygen.

Biofuels made from plants like corn and sugar cane can and do impact global food supplies by utilizing fertile land and fresh water for fuel instead of food. Algae, on the other hand, can be grown using land unsuitable for food production, and can thrive in treated wastewaters in brackish or saltwater.

Algae are also highly productive, with the potential to yield greater volumes-per-acre than any other biofuel source, and unlike other crops can be grown year-round in special manmade ponds or enclosed in photobioreactors exposed to abundant sunlight.

Algae-based biofuels can also be more easily integrated within current infrastructure and with the existing vehicle fleet. This research and development program would involve multiple phases and, although each will have its own unique set of challenges, we expect to spend about $600 million if the project milestones are met.

Development and deployment of industry-leading technology also provides competitive advantages for our Chemical business, where we focus on breakthroughs in three key areas. The first is advantaged feedstocks. Technology delivers advanced optimization tools and flexible process designs that allow our plants to respond quickly to changes in feedstock quality, availability and cost. This enables us to process the broadest range of feedstocks in the industry.

The second is a lower-cost manufacturing process, where advanced processes and catalysts help us improve energy efficiency and reliability. The third area is premium product development,

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where new, higher-value products allow us to tailor innovative solutions to meet customers’ needs.

Technology has been and will continue to be a significant advantage for our Chemical company, as evidenced in the following example. ExxonMobil Chemical proprietary technology enables processing in both heavy and light feeds, delivering a competitive advantage. This chart shows the average worldwide feedstock used by industry on the left and ExxonMobil Chemical on the right. Starting at the bottom in blue, you can see the substantial advantage we have in ethane processing capability as a result of our joint ventures in the Middle East, and our world-class, flexible assets in North America.

Ethane is not the only source of advantage. Our assets also have unique flexibility to run low-cost heavy feeds. And you can see our use of heavy feeds, shown in orange, is more than double that of industry. Proprietary technology has been critical in delivering this flexibility, which allows us to optimize feedstock selection to create a margin advantage. In addition to our emphasis on technology, we view our operational excellence as a competitive advantage.

One of the cornerstones to maximizing resource value is reliability and cost management. ExxonMobil applies rigorous management systems to our global functional structure, enabling operating units around the world to quickly and effectively benefit from new learnings and technical expertise. Operational excellence leads to safe operations, which is the most important result, but can also result in superior profitability.

Facility reliability is — directly impacts the bottom line. We continue to achieve operated uptime to the level of more than three percentage points higher than those fields in which we have an interest in that are operated by others. This is the equivalent of about 62,000 oil-equivalent barrels per day of additional production at little to no incremental capital investment. Similarly, investment selectivity and cost management ensures we are prioritizing opportunities globally while constantly identifying and capturing efficiencies in our operations.

Rigorous, high-quality project management consistently delivers industry-leading project execution performance. The chart on the left shows the average variance between the actual and funded costs for projects started up between 2006 and 2010. The red bar represents ExxonMobil-operated projects and the blue bar reflects ExxonMobil projects that are operated-by-others.

Over the last five years, we have delivered operated-projects, on average, within 1% of funded cost, while similar projects operated-by-others were on average 14% above budget. Decades of project management experience combined with a comprehensive suite of processes and tools ensures consistent results, allowing us to deliver comparable projects at a lower cost and in a lower cycle time than our competitors.

ExxonMobil’s ability to manage — to maximize asset value is also the result of effective cost management. As you can see, all in our industry experienced increases from the recent overheated cost environment. However, we were able to mitigate these market factors and begin

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to turn the cost curve down. Our disciplined and consistent approach to cost management results in a continual effort to maximize the value of each asset.

We employ global contracting strategies and apply best practices in global operations. And as we have mentioned, we continuously high-grade our asset portfolio. Our approach to operational excellence has served us well, as is evidenced by the success of our world-class joint ventures in Qatar.

Since the mid 1990s, ExxonMobil has worked with Qatar Petroleum to design and build 12 LNG trains and domestic gas facilities in Ras Laffan Industrial City. As a result, ExxonMobil participates in the delivery of 62 million metric tons per year of LNG capacity, which contributes to Qatar’s achievement of reaching total LNG production of 77 million tons per year.

In addition, we achieved a significant milestone in Qatar with weekly production capacity of 1 million barrels oil equivalent. Contributing to this success is strong uptime performance, which has been above 95% over the past five years and was above 96% in 2010. ExxonMobil has, and continues to play a key role in developing, transporting and delivering LNG to customers around the globe, including participation in regasifaction terminals in the United Kingdom, Italy and the United States.

We also work diligently to maintain and grow our cost advantage in the Downstream by capturing integration synergies with our Chemical business and maximizing the value of our scale. Energy is the largest component of cash cost for refiners. As you can see on this chart, energy intensity across our refining system continues to decline, while energy intensity within the industry has increased. Our Global Energy Management System and our continuous selective growth in cogeneration capacity are supporting our refineries’ becoming more efficient.

Further, in our Lubes and Specialty businesses, we have upgraded high energy consuming systems to reduce energy consumption and resulting costs at our lube blend plants. Since 2004 ongoing efforts to optimize the Lubes and Specialties businesses have resulted in significant improvements through the consolidation of order centers by over 65%, rationalization of blend plants by over 50% and the streamlining of products by over 40%.

In the Fuels Marketing business, we have reduced the number of customer service centers from 39 in 2000 to four in 2010. And we continue to transition to a more efficient branded wholesaler model in the United States. We have achieved and continue to pursue additional efficiencies and productivity across the Downstream business by moving to consistent global processes, including centralization of support activities, innovative technologies and investments in work processes and systems.

Similar to the Downstream, the Chemical business has steadily improved operating efficiency. As this chart shows, the energy efficiency of our steam crackers has consistently outperformed industry and has improved at a rate one-third faster than the industry. This strong performance is achieved with operational discipline and the implementation of best practices shared throughout

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our global organization. Advanced proprietary technology has also enabled key process enhancements. As a result of our approach, we achieved record performance in 2010 in the area of energy efficiency.

The Chemical business has also focused on simplifying its business to deliver cost savings and operational efficiencies. This chart shows the steady decline in finished product inventory, number of supply points and number of finished grades. We apply the same disciplined approach to marketing and supply chain functions as we do to manufacturing. By continually upgrading our offer, we focus on value capture while still meeting our customers’ needs. Eliminating unnecessary complexity from our supply chain allows us to lower cost, while improving overall supply reliability to our customers.

The value of integration has been a topic of particular interest in our industry over the past year. Others have taken steps to abandon the integrated business model in a deliberate way, some with direct separations, and others through a piecemeal fashion of attriting the integrated business. And these may very well be appropriate actions for those companies.

We examine these same questions on an ongoing basis as to the value of the integrated business structure for ExxonMobil. And we conclude our ability to effectively implement value capture across the integration of our business has resulted in significant competitive advantages and shareholder value.

The effective and efficient implementation of a complex, integrated business model allows ExxonMobil to capture significant value across the supply chain at our manufacturing sites and more broadly, in the management of critical, common activities. Our integrated supply chain enables us to maximize resource value across the value chain.

With over 75% of our global refining capacity integrated with chemicals or lubes operations, joint feedstock and facilities planning at integrated manufacturing sites provide flexibility to reduce input cost and increase margins.

Integration between refining and supply in Fuels Marketing businesses allow us to identify the highest value outlets for our products. Each of our businesses benefits from global competency networks and shared services, which not only allow us to implement best practices, but also result in a very efficient cost structure.

Implementation of the highest standards of risk management in a consistent manner across the globe leads to operational excellence in each of the businesses in which we operate. And finally, we are able to develop and deploy new technologies timely and efficiently to further advance and capture value between the business lines.

Let’s take a closer look at the benefits of integration across the supply chain and at our manufacturing sites. ExxonMobil operates one of the world’s largest and most complex supply

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chains. The level of integration is unmatched in our industry. We’re able to maximize value from the wellhead to the customer.

In support of upstream operations, our global supply organization manages the placement of over 2 million barrels a day of equity crude to achieve the best value. At manufacturing sites, we use computer models to optimize operations on an integrated basis to produce the high-value mix of fuel products, chemicals, lubricants and asphalts. And cross-functional teams evaluate product placement alternatives in each market around the world, optimizing sales to the highest-value channels.

Over 75% of our refining capacity is integrated with Chemicals or Lubes. And 90% of our chemical capacity that is owned and operated is integrated with large refineries or natural gas processing plants. At integrated refining and chemical sites, we employ modeling tools that help us optimize in real-time whether molecules should be made into a fuel product, a lubricant based stock, or sent to one of our chemical facilities for further upgrading.

Using proprietary technology, we have engineered flexibility into our facilities so they can utilize a wide range of feeds, which helps us to reduce input cost and increase margins. We also utilize common site management, utilities and infrastructure. Common global processes and global functional organizations manage the potential of integration value by deploying best practices quickly and efficiently.

Our global scale and level of integration are structural advantages that are difficult for competitors to replicate and are evident in our industry-leading returns. No one harvests the benefit of integration better than ExxonMobil. From 2000 to 2010, our Downstream and Chemical businesses, shown in the chart in red, had combined average earnings of $8 billion per year and a combined average return on capital employed of 20%.

Over this decade, Downstream average ROCE of 21% is more than double the average of competition. And Chemical average ROCE of 19% is more than two and a half times the competitor average. These results clearly demonstrate unequalled benefits achieved through the integration of our Downstream and Chemical platforms.

In closing, the unique competitive advantages we possess lead to superior performance in each of our business lines and serve as the foundation for the creation of long-term shareholder value. Mark Albers and Andy Swiger will now provide a more in-depth discussion on specific areas in the upstream where we will leverage these competitive advantages for future success, including a review of global exploration, major projects and our unconventional portfolio.

I’ll now turn the time over to Mark who will begin the review of our exploration program. Mark.

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Mark Albers (Senior Vice President)

Thank you, Rex, and good morning, everyone. In the next 30 minutes, Andy and I will provide more detail on our Upstream business. I’ll start with a review of our global exploration program and then cover major projects. Andy will then review our unconventional business.

Let’s begin with a review of exploration. As Rex mentioned, we focus on maintaining a very diverse portfolio through the addition of high-quality resources of all types. In the next several slides, I’ll provide a more in-depth review of the quality and the scope of these opportunities.

We’ll start with exploration of unconventional resources. These typically have a very high chance of geologic success. However, the key to commerciality is securing an attractive position early at low cost and then achieving industry-leading unit cost of production and yield. This is, of course, where XTO has given us such a strong advantage. As you can see, our unconventional scope is truly global, with a growing number of opportunities that we’re pursuing in North and South America, Europe and Southeast Asia.

We’re also pursuing opportunities in established, conventional basins. These are high-quality prospects with moderate size potential accompanied with moderate risk exposure. We’re going to continue activity in the basins where we’ve been successful in the past. This is the deepwater Gulf of Mexico, Norway, West Africa, Indonesia and Australia.

And finally, we’re pursuing a number of new play tests. By their very nature, these carry the highest risks, but also the highest potential. A notable example from our past is the discovery of the deepwater Angola play in Blocks 15 and 17. New play tests that we have planned in the near term include the Black Sea, Vietnam and Tanzania.

Looking forward, you can see that the portfolio also includes a balanced exposure to both oil and gas. Over the next few minutes, I’ll share a couple of specific examples of our balanced approach to managing exploration risk and growing shareholder value. As Andy will speak to the unconventional business, I’ll focus on the other two categories of opportunities, beginning with the moderate size, moderate risk, new discoveries in the established Gulf of Mexico basin.

We have a strong acreage position in the Gulf, which totals 2.1 million net acres. Following a gas discovery at Hadrian South, we made a large oil discovery last year at Hadrian North in Keathley Canyon with the Hadrian-3 wildcat. We will resume drilling to continue appraisal of the Hadrian complex as soon as permits are granted by the Bureau of Ocean Energy Management.

As you know, we and other members of the Marine Well Containment Company recently announced the readiness of a containment system, while work continues on an expanded system to be deployed next year.

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In the western Gulf, we have acquired and are processing new large scale wide-azimuth surveys on the acreage position which is on trend, as you can see, between the Great White, Hoover-Diana and Tiber discoveries as shown in the bottom left. This will support growth in the prospect inventory and provide attractive opportunities on an ongoing basis.

In the next chart is an example of the higher risk, but higher potential portion of our exploration program in the Black Sea. With 6.3 million net acres, we have a strong position that offers exposure to a number of plays in the region. The Petrobras-operated Sinop-1 well was a key play test in the center of the Black Sea and was completed in the third quarter of last year. The well did encounter hydrocarbons, but not in commercial quantities. And this, of course, provides very important insights as we direct exploration activities to test the other plays in the basin over our 6 million acre position in Turkey and Romania.

We’re mobilizing the Deepwater Champion to drill in the Black Sea and anticipate spudding the first ExxonMobil-operated well in the second quarter of this year. As you may have heard, we’ve recently signed a framework agreement and are progressing final agreements to jointly explore and develop the almost 3 million acre Tuapsinskiy Block on the Russian Black Sea shelf.

So with the Black Sea example and the Gulf of Mexico example, I’ve shown you the kinds of opportunities we’re pursuing to add quality resources to our portfolio. And while the future mix of discoveries may vary between unconventional, conventional and new play tests, our approach delivers high-quality resources that exceed production year in and year out. And that’s shown on this next chart.

The chart on the left shows annual resource additions over the last decade. By-the-bit additions are shown in the dark blue portion of the bars and discovered undeveloped additions are shown in light blue. Resource additions have more than replaced annual production each year, as shown by the black dashed line. Last year, ExxonMobil added 2.8 billion oil-equivalent barrels by-the-bit and over 1.9 billion oil-equivalent barrels of discovered undeveloped resource.

The chart on the right shows our average finding costs, which compares favorably to those reported by competitors. In their analyst briefings last year, you’ll note that our competitors reported a range of timeframes for their finding costs. But we’ve shown a five and a 10-year average for ExxonMobil for comparison.

Let’s shift gears now and move to an update on specific project development activity. The project portfolio includes over 130 opportunities and remains strong in terms of resource quality, profitability and resource diversity. Let’s begin with the deepwater.

The Kizomba Satellites Phase 1 project is expected to produce an additional 100,000 barrels per day gross, or 40,000 barrels per day net. The project includes subsea tiebacks to the existing Kizomba A and B floating production storage and offloading vessels, one of which is shown on the photo on the left.

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Execution activities are progressing toward an anticipated startup around mid next year. In addition, development planning continues for several other discovered resources on Block 15 including Phase 2 of the satellites project involving Mondo South which was just discovered in 2009. Of course, we also continued to progress execution activities with our partners on three large projects in Block 17, which will provide peak production of 360,000 barrels per day gross or 70,000 barrels net.

Let’s move now to Arctic development activity in eastern Russia. The latest phase of the Sakhalin-1 project, Odoptu, started up last year at the end of the third quarter and is averaging more than 50,000 barrels per day gross. In addition to meeting cost and schedule expectations, it is also delivering exceptional uptime performance.

The Odoptu development utilized the Yastreb rig, one of the world’s most powerful onshore rigs, to drill seven extended reach wells up to seven miles offshore. We recently set a new world record for extended reach drilling on the Odoptu OP-11 well. Employing proprietary drilling capabilities, this well reached a total measured depth of 12,345 meters or seven and a half miles, with a horizontal reach of 7.1 miles from shore and was completed in only 60 days.

The next phase of Sakhalin-1 development is the Arkutun Dagi project. Major projects have been awarded and construction is well under way on a gravity-based structure. This development will yield — will require approximately 45 wells and is expected to yield a peak production of 90,000 barrels per day gross. Startup of Arkutun Dagi is anticipated in 2014. Total peak capacity additions from Odoptu and Arkutun Dagi are 140,000 barrels per day gross or 45,000 barrels net.

Let’s move now to another development in eastern Canada that leverages our Arctic experience. The Hebron and Hibernia Southern Extension projects will develop over 750 million oil-equivalent barrels, contributing peak production of 180,000 barrels per day gross, or 60,000 net. We recently awarded the Hebron topsides and gravity-based structure front-end engineering and design contracts. We’re working with local businesses to undertake construction of the gravity-based structure in Newfoundland.

Extensive Arctic experience and capability positions us well to advance Hebron and development of several satellite resources in eastern Canada. Hebron full funding is targeted for the middle of next year.

Our portfolio also includes a strong presence in North American oil sands. The Kearl project represents one of the largest and highest quality oil sands mining projects in the Athabasca region, with over 4 billion barrels of recoverable resource. By employing proprietary technologies, such as our high temperature paraffinic froth treatment, which removes the need for an upgrader, we expect Kearl to be one of the lowest unit cost oil sands projects in the industry.

Initial development is progressing on schedule for startup by the end of next year, with initial production rates reaching 110,000 barrels a day. With the combination of debottlenecking and

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expansion, the long-term plateau volumes are expected to reach 345,000 barrels per day. These long-plateau volumes are advantageous relative to traditional decline driven production profiles and obviously provide a long-term earnings contribution.

The chart on the left demonstrates how the production profile of a typical industry Gulf of Mexico project compares to the decades long plateau of the Kearl project. The chart in the lower left uses public data from Wood MacKenzie to compare the profitability of a typical industry Gulf of Mexico deepwater project with Kearl, using 2010 actual oil prices.

The red and the blue portions of the Gulf of Mexico deepwater bar are shaded to reflect the low and the high ranges in the Wood Mac data. As you can see, Kearl has lower unit development and operating costs than a typical new industry deepwater development. As shown by the orange shading at the top of the bars, Kearl’s remaining revenue available for earnings and government take is competitive with industry Gulf of Mexico projects despite the discount for bitumen relative to crude oil.

Early last year, ExxonMobil signed a 25-year agreement with the government of Iraq, which includes development of discovered developed and undeveloped reservoirs in the West Qurna Phase 1 license area. We’re leveraging global experience in project execution, production enhancement and facility and operations integrity to support this work effort. Since the signing, we have established a presence in both Basra and Baghdad, including field camps and offices to house the new field operating division.

More recently, we have awarded early contracts for drilling, well workover activities, field facilities and maintenance, and have increased production by 30,000 barrels a day to 274,000 barrels per day.

We’re also advancing work on water supply options, as you’ve heard, to provide pressure support for the redevelopment of this world-class field and to maximize its production capability and long-term earnings contribution. In Papua New Guinea, we’re developing a high-quality 9 trillion cubic foot gas resource. It’s located in the Highlands, which is a very challenging project execution environment. It is the largest private investment ever undertaken in Papua New Guinea and is forecast to double PNG’s gross domestic product.

We’re leveraging industry-leading project execution capabilities to construct a two train, 6.6 million ton per annum LNG plant near Port Moresby, as well as a 450-mile pipeline in the Highlands to transport the gas. All the major contracts have been awarded, and project execution is well under way and on schedule. Long-term sales and purchase agreements have been secured under attractive terms, and ExxonMobil is positioned to maximize the value of this natural gas resource in the attractive Asia-Pacific market. We anticipate startup in 2014.

Let’s wrap up our discussion of exploration and development opportunities with a brief summary of bottom line results, and that is the cost effective delivery of quality proved reserve additions year in and year out. The chart on the left shows exploration expenditures per unit of production

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versus reserve replacement ratio for the peer for the last five years, 2005 to 2009. We’ve removed acquisitions and sales from this data to provide a perspective on organic reserve replacement. Over the period, ExxonMobil has delivered an organic reserve replacement ratio of approximately 120%, at costs which lead the industry peer group.

The chart on the right shows exploration and development cost per barrel of reserves addition versus organic reserve replacement ratio. Over the period, our unit exploration and development costs are among the lowest in the industry peer group. In summary, we consistently deliver competitive reserves replacement with the most efficient use of exploration and development capital.

Now, let me introduce to you Andy Swiger, who will provide a review of our unconventional business. Thank you.

Andy Swiger (Senior Vice President)

Thank you, Mark, and good morning everybody. I will provide an overview of our unconventional portfolio, beginning with a review of our unconventional resource base. ExxonMobil’s unconventional resource base is an industry-leading 35 billion oil-equivalent barrels and has grown by 16 billion oil-equivalent barrels, or almost 90% over the past five years. Unconventional resources now account for over 40% of ExxonMobil’s total 84 billion oil-equivalent barrel resource base.

Continued additions to our heavy oil and oil sands resources, shown in the green bars, have more than offset ongoing production and the expropriation of our Venezuelan heavy oil assets in 2007. The application of technology to commercialize unconventional gas and light oil plays, shown in the green bars, that are contained in our holdings, coupled with strategic captures in 2010, including XTO and the subsequent acquisitions of Ellora in the Haynesville and Petrohawk properties in the Fayetteville Shale, all added to our low-cost resource exposure.

Finally, by-the-bit exploration and development success in the south Texas Eagle Ford, the Marcellus Shale, the Canadian Horn River and the Athabasca oil sands have added low-cost resource gains. Our unconventional resource base is at present split evenly between quality resources in heavy oil and oil sands and the unconventional gas and light oil.

Let’s now look at our unconventional position in North America. As depicted on the map, ExxonMobil’s North American unconventional resource base is diverse by major type — by major play type - heavy oil and oil sands, gas and oil shales, coalbed methane reservoirs and tight gas sands across approximately 6 million acres from northern Canada to south Texas.

In Canada, our leading stake in the Athabasca oil sands region highlights this position, and as noted by Mark, the Kearl project is expected to develop more than 4 billion barrels of recoverable resource from high-quality oil sands. We also have leading positions in the Horn River gas play and the tight oil reservoirs of the Cardium play.

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In the US, we have amassed a leadership position across the spectrum of unconventional play types anchored by 5 million net acres of high-quality properties. ExxonMobil has strong positions in the Barnett, the Woodford, the Haynesville, the Fayetteville, the Eagle Ford, Marcellus and the Bakken Shales, where we have roughly 50 rigs drilling across these plays.

In addition, we have significant acreage in the giant Freestone tight gas trend, in other tight gas fairways across east Texas and the Rocky Mountains and in the long-life coal gas reservoirs of the San Juan Basin and Southern Rockies. We have approximately 20 rigs drilling across these plays. Finally, we have a substantial position in the unconventional heavy oil sand and diatomite plays in the San Joaquin Valley in California.

Two of our fastest growing gas shale plays are the Haynesville of east Texas and the Fayetteville of Arkansas. In the Haynesville, we are running 13 rigs to delineate our 240,000 net acre position. In 2010, gross operated production increased more than fourfold to 240 million cubic feet per day. We have also successfully completed our first wells targeting the overlying Bossier Shale.

In the Fayetteville, by-the-bit gross production has more than doubled in 2010, and then including the acquisition of the Petrohawk properties, we exited the year at 310 million cubic feet per day. We are using nine rigs to both delineate the acreage and accelerate pad drilling across our roughly 550,000 acres. Multiple pilots are under way to evaluate down spacing to optimize ultimate recovery.

In both the Haynesville and the Fayetteville, significant incremental value has been captured through acquisitions. The Ellora acquisition added core acreage contiguous with our prospective properties in both the Haynesville and the Bossier Shales at a resource cost of less than $0.20 per KCF equivalent. Petrohawk acquisition added approximately 150,000 acres adjacent to our current position at a resource cost of only $0.30 per KCF equivalent. Both acquisitions will generate increased efficiencies in two leading growth areas.

One of the central tenets of our unconventional strategy is the application of new technology, which together with operational improvements will build value through higher recoveries and lower unit costs. Barnett Shale, where we are currently producing approximately 900 million cubic feet per day of gross operated gas is a good example of this value creation. In the Barnett, we have been able to maximize long-term ultimate recovery with longer lateral lengths and improved drilling and completion efficiency.

On the left, the graph shows a collection of the highest individual well recoveries to date from the industry on the Barnett Shale, with our wells shown in red. Our superior performance reflects our ability to maximize recovery by identifying and developing the best reservoirs and by optimizing completion and drilling activities.

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The graph on the right depicts the more than 1,350 wells we have drilled in the years 2005 through 2010. Drilling days from spud to rig release have been cut in half to a current average of 14 days, even with longer horizontal laterals.

Declining drilling costs generate lower finding and development costs, and our performance in the Barnett is consistent with what we are experiencing in growth areas like the Haynesville, Fayetteville and Woodford. Simply put, our operational excellence has enabled us to drill more efficient wells, and it is this excellence that we are transferring to our global portfolio. We achieve this strong performance with improved wellbore management, optimized procedures in building horizontal laterals, rig upgrades and multi-well pad drilling.

ExxonMobil has a substantial and growing position in liquids-rich unconventional plays. The centerpiece of this position is our 410,000 net acres in the Bakken Shale of Montana and North Dakota. Currently, we are utilizing seven rigs to drill wells in the Three Forks and the Bakken reservoirs. In 2010, we drilled a total of 63 wells in the Bakken play.

In the Eagle Ford, we hold a sizeable 120,000 acre position across this emerging play, drilling 15 wells in 2010, focused on the gas condensate and oil windows. We are delineating this acreage using two rigs, while leveraging our existing south Texas transportation and processing inventory — infrastructure.

Our position in the Bakken and the Eagle Ford development is enhanced by our vast experience and substantial operations in the liquids-rich Permian Basin, where we hold 470,000 acres prospective for a number of emerging liquids-rich plays. Finally, we are continuing to build positions in a number of other liquids-rich plays across North America, taking advantage of the strong organizational capacity and capability that we have.

We are pleased with the progress we have made on the integration of XTO. Attrition levels remain consistent with historic XTO levels. With the acquisition we have an established, purpose-built organization with deep experience and substantial capability across the broad spectrum of unconventional oil and gas development and production.

Over the medium-term, we anticipate this organizational capability will expand with the support of ExxonMobil’s upstream research and technology. As an important example, we see significant potential to apply technology and expertise to reduce completion costs, which alone represent anywhere between 35% and 65% of a total well cost.

We have already benefited greatly from XTO’s technical support of our global unconventional resource developments. XTO personnel have participated in numerous technical reviews of unconventional projects in Western Canada, Europe and Asia through the sharing of best practices associated with drilling optimization, completions and operations, and by identifying potential resource upside. While it is premature to try to quantify these benefits, we have already seen a positive impact on both resource additions and project planning.

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Other integration benefits include the introduction of our FastDrill technology at the East Texas and Haynesville operations. At the same time, XTO is working closely with our Upstream Research Company to design programs aimed at improving recoveries and increasing development efficiencies.

We also continue to consolidate activities to improve efficiency and grow operational capabilities. Over the longer term, the organizational capability will be further enhanced by the research and development initiatives, and then expanded globally. So let’s now look at our global unconventional portfolio.

ExxonMobil has a diverse portfolio of emerging unconventional resource opportunities. In fact, we presently have access to more than 10 million net acres in North and South America, Europe, and South East Asia. Early entry in the global plays combined with our organizational capabilities will enable us to continue to build our industry-leading unconventional portfolio. With early entry at low cost and long holding periods, efficient data collection and careful evaluation, we are well-positioned to maximize profitability.

Technology development and application will be one of the key elements in maximizing the full value of these large long-life resources. As we look towards unlocking the value of these resources, our global oil and gas unconventional resource base of 100 trillion cubic feet equivalent provides the opportunity for substantial economic growth in the near to medium term. For example, as depicted by the graph on the left, just our U.S. unconventional production is expected to double over the next decade, underpinned by an inventory of approximately 50,000 drill wells.

The growth in production is consistent with our outlook for the long-term demand in U.S. natural gas markets. The Haynesville, Marcellus, Eagle Ford, Woodford and Fayetteville gas shales are driving this growth. And we expect our liquids plays will be growing as well, as part of this oil-equivalent outlook.

Now, we’ll look at our significant heavy oil and oil sands position. We are growing long-plateau volumes with the heavy oil and oil sands production. Our oil sands and heavy oil resource base is significant at 18 billion oil-equivalent barrels. As shown on the chart on the left, we expect to maintain our production from the heavy oil properties while oil sands volumes grow by over 500% by 2020 driven by large projects in Canada, such as Kearl.

When taken together, our significant unconventional gas and heavy oil and oil sands resource base provides a deep inventory of attractive opportunities to grow our gas and liquids production. Additionally, these resources serve to mitigate risk and provide investment flexibility in the overall ExxonMobil portfolio.

If we consider what it takes to unlock greater value from a particular resource type, we can identify several key factors which are common for large opportunities. Superior value creation relies on four key elements. First and foremost is access to a material high-quality resource

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supported then by growth of market demand, emerging technologies and growing organizational capability. An example is deepwater where our large projects in Angola are a good representation. This new tertiary deepwater play was transformed from a series of large discoveries in the mid to late 1990s through large scale deepwater production over five years ago.

A second example is our large LNG projects in Qatar, which transformed the North Field from a stranded gas resource in the mid 1990s, to a major value driver today. Today, these large LNG projects are delivering significant long-term plateau production volumes to LNG markets around the globe. Both these cases, the application of technology coupled with leading organizational capabilities, has unlocked significant long-term value.

We see unconventional resources in a similar way but at an earlier stage, with significant potential to deliver shareholder value. Thus we are building a leading unconventional portfolio to which we will apply leading research and development capability coupled with a strong existing technical and operational capability to unlock substantial value in the coming years. We fully expect unconventional resources will provide material growth and attractive returns, similar to those associated with our deepwater and LNG resources.

I’ll now turn the time back over to Rex, who’ll provide some summary remarks.

Rex Tillerson

Well, I want to thank Mark and Andy for their remarks. I am quite proud of both our operational performance and our financial results this past year. I hope we’ve provided you an appreciation of how ExxonMobil will continue to be successful in each business in which we operate. As all of you can well appreciate, our primary focus is to maximize shareholder return over the long period of time. And we strive to do so at a rate greater than our competitors, and greater than the broader market.

For a capital intensive industry like ours with long cycle times to convert investments to earnings, financial results and stock market returns are also best viewed over some period of time. ExxonMobil has generated greater shareholder value than the broader market, and greater value than the average of our industry competition over the last 20, 10 and 5-year periods.

Most dramatically, over the last decade the S&P 500 annualized return was 1.4%, versus ExxonMobil’s annualized return of 7.7%. When looked at over a 20-year period, ExxonMobil has returned an annualized 12.2%, or 1.8 percentage points, higher than the average of our competitors.

Another way that the value created by the Company has been delivered to shareholders is through the increasing per share ownership of ExxonMobil’s underlying assets and operations from our consistent and substantial share purchase program. Each share of ExxonMobil has an interest in 28% more production volumes today than it did in 2006. Comparing these results to

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our competition reinforces the beneficial effect of the share purchase program for our shareholders.

Since 2006, ExxonMobil has delivered annualized oil equivalent production per share growth of 6.3%, more than two percentage points higher than our nearest competitor. Share repurchases have had a similar ownership concentration effect on reserves growth. Each share of ExxonMobil has an interest in over 32% more reserves today than in 2006. Since 2006, ExxonMobil has delivered annualized reserves per share growth of over 7%, nearly four percentage points higher than our nearest competitor.

The combination of ExxonMobil’s industry-leading business results and share purchase program represent a powerful and prudent approach to delivering shareholder value. This value is further reflected in earnings per share. In 2010, earnings per share were $6.24, demonstrating strong underlying business performance. The bars on the left show the cumulative impact of the share purchase program on earnings per share since Exxon and Mobil merged.

Earnings per share in 2010 were 42% higher than would be the case if 2010 earnings were divided by the number of shares outstanding in the year 2000, the first year of the merger. And this is across a decade of record capital investments in quality opportunities that will deliver earnings and cash flow for years into the future. Importantly, we have maintained this approach through each business cycle, good times, tough times.

Now, I’d like to share our long-term investment plans and the impact those plans will have on our production volume outlook. ExxonMobil has maintained robust investment programs through the business cycle. Our projects, as always, have been evaluated using a range of prices and other variable factors to support attractive returns under any likely set of business conditions. We are executing a large inventory of high-quality projects. Actual spending in a given year will vary depending on the pace and the progress of each project.

We are anticipating an investment profile of approximately $34 billion in 2011, and a range of $33 billion to $37 billion dollars per year through the year 2015. While prices have declined for a number of key commodities and services since the highs of 2008, we continue to aggressively pursue cost reduction opportunities. These estimates represent our best view as we look to the years ahead.

Let’s now look at how the investment plan will impact upstream production growth. Before I provide an updated volume outlook, and since there has been a fair amount of change in our portfolio, I think it might be useful to revisit the forecast we provided to you at this meeting last year. If you will recall, we expected that production would grow between 3% and 4% in 2010, and about 2% to 3% per year on average over the period of 2009 through 2013.

The outlook we provided last year is shown in green on the chart to the left. The blue dashed line reflects our current outlook for the same period. Excluding XTO, our actual 2010 volumes relative to 2009 grew by 6%, well above the 3% to 4% we anticipated at this time last year.

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Although we have seen some variability from year to year, our volume outlook from 2009 to 2013, excluding XTO, remains unchanged at about 2% to 3%.

This chart shows our total Upstream production outlook from 2009 through 2014, including XTO. As result of continued strong operational performance, high-quality projects and the successful integration of XTO, volumes growth is forecast to remain strong. Of course, the actual production in any specific year can vary above or below what is reflected here due to variables such as price, quotas, divestments, weather, regulatory changes, and geopolitics. But with that understanding and on that basis, during this timeframe, we expect volumes to grow by 3% to 4% in the 2011 — in 2011 and by 4% to 5% per year, on average, over the period of 2009 to 2014.

This outlook is shown in the graph on the left. Base volumes from all of our fields currently online are shown in green. This area includes future work programs. As many of you are aware, this production base has typically declined by 5% to 6% per year. However, in part due to increasing levels of unconventional long-plateau volumes, we are expecting the decline to be about half of that historic rate at around 3%.

In addition, our volume outlook remains balanced, with strong contributions from both liquids and natural gas. This chart provides the liquids and gas split of our forecast volumes. Liquids production, which is shown in green is anticipated to grow by 2% to 3% per year, on average, reflecting the addition of XTO and benefits of major project startups. These projects will also add to our already strong base of long-plateau volumes.

As demonstrated by our strong financial and operating performance, ExxonMobil remains the leader in providing reliable, affordable energy in a safe, secure and environmentally responsible way. The quality, size and diversity of our resource and asset base across the business are balanced, while all our focus on disciplined, selective investments underpins our ability to deliver superior returns.

We are proud of our ongoing efforts to identify and develop new technology that enables us to be more competitive and efficient. With a focus on operational excellence, we develop and deploy systems to consistently apply the high standards leading to best-in-class operating performance. And finally, we capture substantial value across business lines through integration. We have built processes and systems that enable our organization to capture the highest value for each molecule. The integrated business model has placed many of our businesses at the top of their respective areas of competition.

In most of the areas in which we compete, ExxonMobil is considered the premier organization. Our disciplined approach to operations and investments enables each and every one of our businesses to generate strong returns. We are the largest producer of liquids among major integrated oil companies and are well-positioned for future growth with our high-quality, low-cost oil sands project at Kearl.

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With our world-class investment in Qatar and future LNG projects, we are among the leaders in the LNG value chain. And with the acquisition of XTO, our growing unconventional portfolio around the world, we have created the premier unconventional gas Company.

In the Downstream, not only are we the largest global refiner but we also stand as the number one supplier of lubricant basestocks. We also have the highest return Chemical Company and the competition is not even close as we generate returns more than two and a half greater than the competitor average.

The sum of the value of the different parts of our business is significant, even if not always recognized, as evidenced by our leadership in the areas in which we compete. However, we manage the corporation to capture the sum-of-the-parts plus. At ExxonMobil, we leverage financial strength, rigorous management systems and operating synergies to capture additional value for shareholders across our businesses through that integration.

That concludes my prepared remarks. With that let me turn it back to David who will review the remaining agenda for you.

David Rosenthal

Thank you, Rex. At this point in the program we would like to take a quick break. I would ask that you limit the break to about 15 minutes, and let’s all plan to be back here ready to start the Q & A session at 11.15. Thank you.

BREAK

QUESTION AND ANSWER

David Rosenthal

If I could ask everyone to take their seats so we can begin the Q&A session. All right, thank you very much. At this time we’d like to begin the Q&A session. We’ve allocated about 45 minutes for that, and we do plan to end the meeting at noon. So at this point I’ll turn it over to the Q&A.

Rex Tillerson

We decided we’d get comfortable since all of you look so comfortable. I asked David if we couldn’t get the Yule Log on the screen up there but they couldn’t arrange it. Yes, go ahead.

Question 1

Rex, you guys enjoy a variety of competitive advantages which have led to fantastic returns over the longer term. And when I think about the industry today there’s a variety of what seems to be

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new or emerging competitors out there that seem to have lower capital costs or return hurdles than some super majors do, such as yourself. So my question’s really threefold.

First I wanted to see — excuse me — if you could provide kind of an updated assessment of this new competitive framework, and two, whether you feel that the growth and returns profile is going to be challenged in the future in relation to years past? And then just finally if there are any implications for distribution policy at ExxonMobil specifically?

Rex Tillerson

Well, the competitive environment, I know that you don’t want to hear me say this, the competitive environment’s always changing. Okay? That’s not a new event in the 100 and now almost 28 years we’ve been doing this.

Clearly over the course of the last decade the emergence of the national oil companies onto the scene there’s many of them who — some are — who’ve been around a number of years and come with a certain competency around investing and operating the kinds of things we do, is they’ve left their home country borders and now entered into the international marketplace, is I think probably one of the most significant recent events in the competitive landscape.

There are also brand new national oil companies that have emerged out of these governments in transition from the breakup of the Soviet Union to China becoming more integrated with the global economy. And all of those come with different sets of capabilities, and they also come with, in my view, a lot of different objectives. And so it’s very — I think it’s a mistake to try to characterize everyone the same out there because clearly they all have both different capabilities, and different objectives.

And so, as we look at opportunities in the future you do look at who’s the competition, who are you having to compete against in this particular resource arena or this particular chemical venture, whatever it might be? And you always go through an assessment of do you want to try to just capture this thing head-to-head? Do you want to try to joint venture with someone? And obviously that is very dependent on what the host country — who the host country is as well in terms of how they might view that.

And that involves evaluating that each of these players in terms of okay, if we joint venture what value do they bring? Because the only reason to partner with anyone, unless you’re just forced to, and a lot of our partnerships were forced marriages that we wouldn’t necessarily have picked them the way they are, but if you have a choice the question is always what value do they bring to the opportunity? So that’s the way we deal with it on a pursuit basis.

The way we deal with the impact on economic viability of resources is we have to create the value that they can’t. So if we just approached it on kind of a base head-to-head competition and they’re willing to take a 10% return on something and we’re not willing to take anything less than

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a mid-to-high teens, okay, how do we try to close that gap and still capture the opportunity? We have to do it with all of the things we’ve talked about.

We have to do it with better project management, which means we’ll get it done at a lower cost. We have to do it with better operational competencies and cost management. We have to bring technology. We have to find solutions to open the space back up for us.

And so in many cases you could look at opportunities we capture and say, well, gosh, on a base business that looks like about a 10% to 11% return deal. And on base with no change it very well might be. We enter it with a view that we’re going to take that 10% to 11% on the current conditions opportunity, and we’re going to improve it to a mid-to-high teens return.

Now, one of the reasons we can do that is because we have this enormously large resource base we’ve shared with you, which is also very diverse, as we shared with you, geographically, technology and [kit] requirements. And the whole key to our disciplined approach to investment is that you have choices. And with that large resource base, and that diversity, we can still manage a selective investment process. So that there’s nothing that we feel at, any given time, if we don’t capture this we’re going to sink the Bismarck, or we’re going to really lose ground here.

It’s not that they’re not important and they’re not material, but we, I think, are afforded the opportunity to be very patient, and be very persistent in our pursuit of those. And then if we capture it at conditions that, say, today might look like 10%, 11% or something that’s certainly below where our objective is, we’ve done that with a view that we already can see opportunities that we can bring to that to improve that. And that’s in fact what we have done.

And that’s why the Kearl project that Mark highlighted for you is kind of a good example. If you’d have looked at that on the way we did things five, six, eight years ago we wouldn’t have gone forward. We’re going forward because we have brought some new technologies to bear. We’ve brought some new approaches to the project management, the concept design and a new approach to the phasing of how to develop that resource over its life. That creates the space to now earn the returns that we want.

So that’s the way we have to respond to it is we just have to create the value out of what we can bring as a response to the competition that is willing to accept 10% in the base case and be happy with it.

Question 2

If I can try a couple? First of all, your capital expenditure guidance going forward, I really wanted to address the issue of capital intensity of your overall portfolio because you’ve brought a lot of long-life projects into the asset base, Qatar obviously being the main one. How does that change the required maintenance capital, if you like, in the context that your CapEx is continually going up but you’ve got this big long-life asset base? Could you address that in the context of future capital expenditure?

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But also in terms of dividend distributions because with greater visibility on the base why the need for the flywheel in the share buybacks and not a little bit more split or biased towards dividend? And if I may, I have a follow-up.

Rex Tillerson

And again, the question around the maintenance — you’re talking about maintaining that level of capital spending or —

Question 2 (clarification)

Yes, the capital expenditures continue to ramp up, but you’ve now got this stable base where you don’t have to fight the decline, so just trying to understand what’s going on with the delta?

Rex Tillerson

Well, it is, has been and always will be the attractiveness of the investment opportunity. And as we’ve said many times, the volumes are an outcome. They’re not an ingoing objective. We just do the sums on the projects we think are good investment opportunities and that’s what the volumes turn out to be.

So we — as we’ve never been and we’re not driven now towards some volume maintenance objective. It is purely about the opportunities in front of us that we can fund with the capital program and believe that we could execute them and it will generate the values we want in the years to come. And that’s what really determines the level of activity.

As to how that might change our view around cash management and the balance between dividends and share repurchase, we were mindful of wanting to ensure that we provide those growing dividends to our shareholders. Of course the disclaimer is in full force here. We can’t predict or promise anything, but our track record is pretty well-established.

And we continue to believe that the share repurchase does provide a couple of significant values to shareholders. The ownership, obviously, for those who retain their shares, but it also is providing good liquidity in the market for our shares for people who need and want to take their earnings off the table. Or have, in the case of a pension or a fund, needs to have that ready liquidity. We’re in the market buying some shares all the time.

Is there a point at which there’s a magic graph that says, okay, when you get the share purchase program going at this level they intersect and you say, okay, that’s it? Now we want to really boost the dividend? There’s really no magic number there because it’s always looked at and considered in the context of the capital programs, because the first thing we want to do is be sure we’re not losing any investment opportunities for a lack of financial capability.

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And I know a lot of people would say, gee, you’ve got huge financial capability. And that’s true, we do. And having that gives us a lot of optionality to consider a very wide range of investment and value capture opportunities, including like what we did with XTO this last year.

That we can approach those things from a lot of different perspectives so I wouldn’t want to suggest that you’re going to see a huge change in our approach and policies toward dividend and share repurchases, certainly not in the near-term because I don’t see any compelling reason to do that at this time.

Question 2 (follow-up)

My quick follow-up is on the XTO opportunity set. A lot of your competitors have shifted capital towards liquids as opposed to gas. If you could just discuss how that’s changed at XTO and I’ll leave it there. Thanks.

Rex Tillerson

I’m going to let — since Andy kind of focused on unconventionals let me let Andy comment on that one.

Andy Swiger

Sure. What I would say is as with every opportunity we look at it’s not what the hydrocarbon is. It’s the attractiveness of the opportunity. Can we get a high-quality resource base of sufficient materiality that we can then begin to apply the technology, apply the operational capability and make it into something that’s very valuable to the shareholders.

And that’s what we saw as an opportunity with XTO. When we’re looking at the unconventional space over a number of years, looking to find out whether we’re going to be able to find a material resource opportunity there, XTO was a great fit because not only did we get a material resource base, we got a great organizational capability with it that we can expand globally now as I talked about in the conversation that we just had.

So it’s not a focus on gas versus oil or any one of the categories of resources we have. It’s where are the high-quality and material resource bases that we can make better and better and even expand the capability around the globe there? That’s the driver behind XTO and that continues to be the focus of what we’re trying to do with XTO. We’re making it better and better every day.

Rex Tillerson

I think that mix question of are we trying to shift more to liquids? Not in a deliberate way. As Andy said, and as I implied with earlier discussion on our investment philosophy, if it’s going to generate a good return for us and that’s — I’ve kind of given you an indication the kind of returns we like — as long as it passes that test and we don’t have a capital limitation where we’re having

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to now say well, I realize that generates a high teen return but we’re capital constrained so it goes on the shelf so we can do something that’s in the 20s.

Today we don’t — we’re fortunate that we don’t have that kind of constraint so it doesn’t matter whether it’s a gas or a liquids-rich well. They look at it well by well. If it’s generating the kind of returns and attractive economics we like, we’re funding it. We’ll tell them to go ahead.

Let me go to somebody on this side.

Question 3

I’ve got two questions on gas. With the unconventional graph that you showed there wasn’t a lot of volume growth for the overall gas growth globally. You had a long-term chart showing Europe, Asia and the U.S. You showed a lot of unconventional gas growth in the U.S., but a relative dearth in Europe. Is that Exxon’s geologic call about unconventional gas in Europe?

Rex Tillerson

Well, we’ve not made a call on the unconventional gas potential in Europe. I mean we are at the very earliest stages of even testing the resource. We have drilled not even a handful of wells in some very large areas that we have rights to. So we’ve not made a call one way or the other, and so we’re not going to put something in the outlook that we don’t know enough about at this stage. So I wouldn’t read that as a positive or a negative on our view of unconventional resource potential in Europe, because quite frankly, no one has enough information at this point to know.

We’re really at the earliest stages of even understanding whether the techniques that have made the unconventional shale gas in North America so successful, whether those are going to be applicable and give you a similar result in Europe or not? And we just don’t have the information yet so that’s why you don’t see much in there.

I think some of that is coal bed methane gas. You’ve got to remember what’s in the unconventional. It’s a mix of a lot of different things and so that little bit of wedge you see in there, clearly there’s a lot of coal. A lot of coal in Europe and it’s been very — ever so lightly explored from a coal bed methane standpoint. So there’s some potential there that I suspect, and we suspect, will be developed. But it’s pretty insignificant because we don’t know enough to make a call on it right now.

Question 3 (follow-up)

Okay. With respect to US gas we have [toddler] level prices right. You’re a returns-focused Company. Do you have HBP issues in terms of your acreage which is why you’re still actively drilling or are these projects really meeting your return threshold?

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Rex Tillerson

While we are, clearly, when we look at the seriatim of wells and the activity, we want to ensure we hang on to a lot of acreage that we have acquired. A relatively small, and Andy probably knows direct — in fact I’ll probably have him just answer — a relatively small portion of that drilling program is driven by HBP drilling.

Andy Swiger

Yes, that’s a fair characterization of it. It’s relatively small. There’s some.

Rex Tillerson

So a lot of it is currently HBP which is good because we can pick and choose and pace where we want the rigs to go to deliver both the best value but also to help us continue to appraise this very large acreage set we got in the XTO merger. There’s a lot of that acreage. We need to get a well in there just so we can fully assess what the value of the resource base is and that’s — you saw some change in the resource base this year.

That was after a pretty extensive evaluation of all the drilling XTO had done over the last year and a half since they last updated the resource base. So like all these things as you get more wells down then you know more about more quantitatively what you believe your resource potential is.

Yes, right here.

Question 4

Just to follow up on that series of answers and then ask you a wider one about volumes. Could you triangulate the US gas picture for us between the gas price, the levels of activity you have and the volumes you’re achieving? I know you’ve passed on a bit there, but I was just wondering at these prices it seems that your activity based on your charts remain flat so you’re not cutting activity. But I also think if I remember right, maybe you’re quite a way below what you said you’d be at, say, for example a year ago in terms of activity. I think you mentioned 50 rigs right now.

So could you just triangulate between how you look at even the potential for less activity in the US perhaps cutting it because of low gas prices, the productivity that you’ve talked about per rig, and then how that would relate to your volumes? And then I’ve got a follow-up on volumes.

Rex Tillerson

Well, I think we’re closer to 70 rigs, but I’ll let Andy give you the details.

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Andy Swiger

Yes, it’s 50 rigs in the shale plays, 20 some rigs in the other plays so we’re at the 70 to 75 level, which is essentially what we said last July when we gave the update then. So we haven’t cut it nor have we increased it. And as per the previous answer, we’re spending a lot of it delineating where we’re going in places like the Eagle Ford and so forth to map out what the future plans are going to be.

There’s a little bit of lease maintenance as we discussed before, and then there’s a lot of good opportunity drilling. All plays are not equal. Some have better economics than others so we’re shifting around and we’re pursuing very economic activities with the bulk of those rigs, but about the same level that we said last July.

Question 4 (clarification)

Yes. So I misunderstood on the 50.

Andy Swiger

Yes.

Question 4 (follow-up)

I thought it was a step down. So there’s a total of 70 which is the number I had in my head. And then the productivity there suggests that even holding that flat you’ll continue to see volume growth from US gas?

Andy Swiger

That’s correct.

Question 4 (follow-up)

Can I just follow that through to a wider volume question? You announced an impressive number which was the decline rate just about half, I think, 3% not 6% which obviously brings a huge boost ultimately to your volumes, but at the same time you didn’t boost your volumes by 3%. Could you just talk a little bit about what went missing, if you like, in the current volume outlook given that performance? Thank you.

Rex Tillerson

Well, the base decline rate changing to the 3% level is reflective of a lot of these plateau volumes. And we’ve been talking about this now — I think the first time we talked about the plateau volumes was four meetings ago. Stuart McGill had a chart that he showed you. And at

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that time he was focused on what the Qatar projects meant in terms of plateau volumes because the Qatar projects, each of those LNG trains and the production volumes that go with them they come up and they stay flat for the duration of our rights to the project.

Add into that then the character of the oil sands, which are coming in in fairly significant — they come in in these very significant blocky type volumes and the oil sands don’t decline. They just kind of hold at that mining and processing level. So that’s what’s really underpinning that change in base decline is there’s just a larger and larger piece of the overall volumes are coming from these types of resources.

The unconventional piece then which enters — while, unconventionals, as you know, they have fairly steep declines in the early life of the wells, but they decline down to a rate then which is very plateau-like, for a long period of time. So while you’ve got kind of a mix of unconventional effect, there are new wells coming on steep decline, but an accumulation with every well of this plateau-type volume as well. And that’s what really underpinning all of that.

In terms of why the overall volumes didn’t move by that much, again, it’s a question of mix in the portfolio. It’s a question of the base, the conventional base and what it’s doing, which is continuing its decline and some view on timing of projects. And so maybe we’ll do better than that. Maybe we won’t do that well. So it’s — I think that outlook that we presented, I think, is a pretty balanced one when you look at everything that’s going in and out of that volume portfolio from all of those sources.

Yes, back over here?

Question 5

Hi, Rex, thanks. Two things, first I wonder if maybe Mark Albers could give us a little bit of a report card, if it’s not too early, and that’s an optional answer, on the new play exploration program? As outsiders we don’t hear a whole heck of a lot about specific play drilling results, so any kind of report card you might be able to offer? Not just the one in the chart which encompassed both the existing basins as well as the new play activity.

The second question relates to trying to get a little bit of a better understanding as to the extent of the nature of the increase in the capital program. Obviously up very substantially from the ranges that you had talked previously, and up by an amount that would exceed, by my math anyway, considerably, just the XTO-related increment.

If you could provide some idea of how much is going to unconventional, what kind of capital outlay, actually backstops Andy’s outlook for unconventional production, looking out over the intermediate to longer term, I would appreciate it? Thanks.

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Rex Tillerson

Well let me answer the second one first and then let Mark answer. The step-up in capital spending to the $34 this year is almost entirely due to the level of spending we’ve put in place for the unconventionals, now that we have an organization that executes, and they can execute these things very efficiently.

So most of that change is, by and large, the impact of this very large unconventional portfolio we have now. Other puts and takes, if you strip that out, it wouldn’t look that different to you. So that’s indicative of the kind of capital spend we think we’ll have in the unconventional.

Question 5 (follow-up)

(inaudible - microphone inaccessible)

Rex Tillerson

Yes, if you added all that up it pretty well accounts for most of that step-up from year-to-year. On the exploration plays, and I’ll have Mark comment for you, but will remind you we don’t make a lot of premature announcements in our exploration drilling program. And we don’t put a press release every time we get a well down that had a hydrocarbon show. We don’t say much about it.

And when we begin talking about it, it’s because we know enough about it that we think it could be material. And we feel we have an obligation to then let the investors know. But early in the stage of a lot of our activities you’re just not going to hear us say anything. Because we don’t — we’re not going to talk about things that we just simply don’t have enough information about.

So we — you may see us drill wells and you might not hear anything about it for a while because we’re trying to figure out whether we got something or not. But with that caveat, I’ll have Mark say whatever he wants to. But I don’t want to get your expectations up that there’s going to be some kind of big announcement.

Mark Albers

Yes, why don’t we, if we can, flip up the chart that shows all the new play tests? Is that doable? Yes, so as we commented, we talked about the Black Sea, kind of that focus there again, very early days on that. And by their nature, as you look at these three different categories, you go from relatively low risk, unconventional, moderate risk, established basin like the Gulf of Mexico, West Africa, and then the new play tests are obviously higher risk, but much higher potential.

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And those risks range can range anywhere from 20% to 40%. I mean, so it’s — you can’t — when you’re drilling that kind of a program, you’ve got to be very disciplined, thoughtful around where you’re going to invest to make sure there’s enough upside there to warrant that kind of risk.

We talked about the Black Sea in terms of where we’re going. Obviously, that’s a key near-term play test. Vietnam’s another one we’ll be drilling this year. Tanzania will be another key play test we’re in with Statoil.

A number of those other dots that you see on the map, we’re in early stages of conducting seismic — getting seismic, processing it, testing prospect inventory and then pursuing those. You’re aware of the dry holes we’ve had in Libya, and some of the dry holes we’ve had in Brazil. Again, given the kind of risk these plays have we’re not rattled by that, or shaken by that. That’s just part of the judgment.

But we’re taking those results now, and as we look at what other opportunities there are in those countries and factoring those in. And you learn an enormous amount from a dry hole in terms of what didn’t work, why it didn’t work, and then how you roll that into the next steps.

Question 5 (clarification)

Mark, would I be incorrect at this point (inaudible - microphone inaccessible).

Mark Albers

No.

Rex Tillerson

Yes.

Question 6

All right, thank you, Rex. Two questions, one over the non-spot years I think the US unconventional shale have totally changed the market and how we look at gas market. There is speculation from some of the investors that whether it’s the shale oil could have a similar effect and also correspondingly, that WTI will consistently, into at least the next 10 years that may be trading at a substantial discount to Brent or [LLS].

First want to see whether Exxon, given that your long history, you probably have more data in the lower 48 than anyone, whether you share that view? And if you do, can you give us some idea that how big you think the potential is the resource plays? And whether your commercial and your logistic operation will be able to take benefit of that potential prolonged dislocation of the WTI?

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The second question is on the global LNG market. Want to see whether you guys have seen any pushback from the Asian buyer for, say, signing oil parity contract and that also, historically you typically have (inaudible) gas cargo will be take or pay and whether in the future that you will shift a little bit more onto the spot market to take advantage, potentially some periodical spike of prices. Thank you.

Rex Tillerson

As to the shale oil resource base, clearly it has been demonstrated to be viable in this price environment. With all the activity that’s focused, by and large the real central area of activity is up in that Bakken play and then a lot of other plays being evaluated, some of which Andy talked about that we’re involved in.

I think it’s in terms of how it evolves into how big of a potential resource for depletion domestically; it’s a little early to say because we don’t have a lot of production history on these wells yet to see how they behave. Does an oil shale rock behave differently under depletion than gas shale does? And so that’s — it’s one of the things that our technologists spend time examining and looking at and trying to understand. In terms of how — it’s clearly been significant here recently because of all the activity.

So I wouldn’t hazard a guess on how big that resource base might be, but there are other oil shale plays, as you know, beyond just the Bakken area. And those are now being — at the earliest stages of wells being drilled to test the viability of those, too. I think the real question is we need a little more production history on some of these plays to understand what ultimate recovery will be and — which will determine the commerciality of these things.

As to the situation on the WTI differential and how that plays to either advantages or disadvantages with us, let — Mike, why don’t you comment on that?

Mike Dolan

Yes, thanks, Rex. I think there’s been a lot written about that. I think it’s pretty well understood there’s a physical issue around Cushing where a lot more oil coming in and there’s not enough pipelines going out. So we’ve got a few years probably before some other pipelines are built or pipelines are expanded to allow that material on the margin to get to the Gulf Coast and then you’ll see it equilibrate back towards a more traditional range.

In the meantime, for our refineries from Canada down into the U.S., because we do have the Canadian crudes we’ve got more oil sands coming and then we have these other crudes that are being bottled up in the Midwest. We are taking advantage of that at our refineries from Strathcona, Canada down to Joliet and Billings in Montana.

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So we’re able to, like all the refiners in the region, we’re able to take advantage of that, to the extent that we have a market for the products. So we’re happily taking advantage of that. We have great flexibility in our refineries to swing between crude. So we’re taking full advantage.

Rex Tillerson

And the last part of your question?

Question 6 (clarification)

(inaudible question - microphone inaccessible).

Rex Tillerson

I got lost in thought. Okay, yes the LNG.

Question 6 (clarification)

The LNG market.

Rex Tillerson

Yes.

Question 6 (follow-up)

Have you seen any pushback from the Asian customer? And also whether in the future your strategy would be changed somewhat to increase the spot sell component of the [project] itself, just totally [without] take and pay.

Rex Tillerson

Yes, Andy, why don’t you —

Andy Swiger

Yes, the short answer on pushback is no. We continue to have good interactions with an ever-expanding universe of customers in Asia. And while there’s some rhetoric out there in the sort of popular press about pushback, we don’t really see it in the conversations.

We always have a vigorous dialogue as to what the actual slope is going to be and the intersect and so forth. But there still — there’s still — the model is out in Asia oil-based contracting. Now, with respect to spot and other types of sales, I mean that’s been in our toolkit for a long, long time. And we’re always out in the market looking for what a buyer, what a customer wants. And

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over the years, including this year, we’ll make sales of three cargos, six cargos, single cargo, 18 months of a strip out there and so forth.

So that’s something we’ve been doing for a long time. It wouldn’t represent a departure at all to do more spot. We do spot based on what the market is looking to get versus what our supply is and what it holistically comes together and says is the optimum economic outcome, so no real change in the strategy there.

Rex Tillerson

I think in Qatar, in particular, as Andy has indicated, we’ve always maintained in those mix of contract structures that we wanted to have some volume of LNG that was divertible. So that we could always seek — with the capabilities we have to send that anywhere in the world that’s got a receiving terminal because of the scale of the ships and whatnot, just to maintain some element of divertible capacity to take advantage of the kind of things like Andy’s describing.

There’s a question back over here. Yes, over here, against the wall. Right there.

Question 7

Many of your peers are actively divesting or rationalizing their downstream portfolio. And I was just curious if Exxon is either just comfortable with their asset base or maybe just not being quite as vocal on their intent to divest?

Rex Tillerson

Well, as indicated in some of the charts, we — asset management is an activity that’s something we have done and continue to do on an ongoing basis. And as I indicated, we’ve sold $40 billion worth of assets over the last 10 years. So we’re always evaluating each asset on a standalone basis. I think your question is probably a little more fundamental. That gets a little bit to the level of integration, maybe, and let me, Mike, why don’t — you want to share some thoughts on that?

Mike Dolan

Yes, I think you saw in Rex’s presentation the kind of results that we’ve been able to turn in from the Downstream and Chemical both together and separately. A lot of that value comes not only from the integration, which is very important, but the technology, the people, the systems we have, the long history we have, and the way we run these things that we are the best operator out there. And we are the most cost efficient, which is what’s vitally important in these businesses.

So you saw that we generated about a 20% return across both those business segments over the last cycle, if you will, the last seven or eight years. It’s a pretty good return. We’re generating a lot of cash. That’s useful to fund all the cash needs that we have in the corporation.

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So as we sit here today, we’re happy with the hand we have. We think there’s still lots of advantage in having the Downstream, the Chemicals, the integration we have. We work well with the Upstream, as well, in terms of placing some of the newer crudes and things and processing some other crudes just for economic advantage. So there’s a lot of integration in ExxonMobil that other companies just aren’t seeing.

So no, you’re not seeing us take the same approach as some of our competitors. Having said that, Rex is right, we’re always looking if our assets are worth more to someone else than they are to us, and we get a lot out of those assets, so that’s a pretty high hurdle, then we’re happy to talk to them if it generates money to the shareholder. And we’ve done that pretty consistently. So — but we’re not out there. There’s no fire sales at ExxonMobil. There’s just good, solid capital discipline.

Rex Tillerson

Yes, back in the middle there?

Question 8

So you’ve told a positive story about slowing decline rates. You’ve got 70% oil price linkage in your base. And a lot of your core growth projects are oily. So with this recent move up to sort of $5 billion buybacks, is that a call on increasing the leverage of Exxon? Or do you think you can fund that from rising underlying free cash flow?

Rex Tillerson

Well, it’s — again, it’s not a departure from the approach we’ve taken to managing excess cash. We’re still generating healthy excess cash. As I indicated, we finished the year at a little over $8 billion, and we had about a $3 billion buyback in that last quarter of last year.

So we literally look at this on a quarter by quarter basis, understanding if the pace of certain capital projects may have moved forward, which says we’re going to need funding earlier, perhaps, than was in the original plan, or something is slipping away and we’re going to have some additional cash available. What do we want to do with it?

And so it really is something that Don and I will sit down and talk about every quarter. Okay, what do we want to do? We know we’ve got a view going into the year as to what we think we might want to do on dividends. But I can tell you the decision on dividends is never made until the night before the Board meets.

And then similarly it’s we funded the capital program and we kind of know what we want to make sure we can do on dividends. What’s leftover, and what’s a prudent way of returning that to the shareholder? And that’s what really sets the level of the share buyback. Obviously we’re happy we’ve been able to maintain the level of share buyback that we have. I think we issued, as

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you know, we issued a lot of shares to effect the XTO merger. That allowed us to make that merger workable to their shareholders.

We also said through our share buyback program we expect we’ll be retiring those. And I think at the current spend and the current price the stock’s at today, by the end of the first quarter we will have bought back 40% of those shares already.

So it’s just about how to get the underlying value back into the shareholders’ hands, back into the shares they own. And that’s why we think that the buyback is an important piece. It’s not the piece. It’s just an important piece of how we manage that excess cash. But there’s no new program, no departure from the way we view it, same way we’ve always made those evaluations.

All the way in the back?

Question 9

Looking at what changed maybe the margin year-on-year in your presentation there’s a little less on offshore exploration and maybe that’s just with more XTO and unconventional, but with also Exxon is the largest producer and was an earlier entrant in Angola and didn’t participate in the recent pre-salt bid round there. I just wonder if there’s any implicit statement on the opportunity set that you’re seeing for enhanced offshore exploration?

Rex Tillerson

Let me let Mark respond and he can kind of tell you the situation in Angola since you asked that specifically, but also then more generally.

Mark Albers

Yes. I mean as you look at the offshore element of our exploration program, Black Sea is offshore. Vietnam is offshore. Tanzania is offshore, Gulf of Mexico offshore, West Africa offshore. We did participate in the — I’m not sure if you said we didn’t or did, but we did participate in the — did participate in the recent offerings for the pre-salt Angola blocks. And we are in discussions now with our partners and Sonogal on the fiscal terms. And if we can secure attractive fiscal terms then we’ll move into the next phase.

But we were offered a position in three blocks which as we looked at the basin were the ones we felt like we wanted to be in from a risk exposure standpoint. We’re pleased with that. We’ll see how the fiscal discussions go and then make a call on future participation. But the offshore exploration is quite, quite active.

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Rex Tillerson

I’m sorry. You had a follow-up?

Question 9 (follow-up)

Yes. (inaudible question - microphone inaccessible).

Mark Albers

38, 39 and 40.

Rex Tillerson

Any other questions? Oh, right here, down front? Yes.

Question 10

Could you discuss the challenges that shale gas has in terms of water? And where the challenges are the greatest if you believe there are challenges and how you’re dealing with them? Is new technology likely to reduce the problem somewhat or at all? Could you just discuss your (inaudible) on just the general topic?

Rex Tillerson

Sure. And you’re talking about the challenges and the concerns over contamination of —

Question 10 (clarification)

Yes, and —

Rex Tillerson

— public drinking water? Yes. Okay. Sure. Well, there have been multiple investigations and studies over the last 10 years or so. The EPA has done two previous studies. They have a third one going on now. Hydraulic fracturing is a technology that’s getting a lot of attention today. Some are of the misunderstanding that this is a new technology and that we just developed it and therefore we really don’t have a lot of experience with it and we don’t fully understand the risk.

I think it’s important to understand hydraulic fracturing has been around for more than 40 years. It dates from the late ‘60s, early ‘70s in some of the [verily] tight gas developments in east Texas and northern Louisiana. There have been over 1 million wells hydraulically fractured in the United States over that period of time. In the EPA’s prior two studies they were unable to

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document a single one case of public drinking water, substrata drinking water contamination as a result of hydraulic fracturing.

Now, are freshwater zones contaminated with salt water, some with oil, some with natural gas? Yes, they are. Generally that occurs due to poor drilling practices and/or poor completion practices and/or just old wells, wells that have been around for 100 years, casing’s finally given way and saltwater and associated gas or sometimes gas lift gas migrates out of the casing and into the freshwater zones, path of least resistance.

Now, that’s not new, and that’s well-known and we understand why it happens. And you mitigate the risk of that with good surveillance programs. And the regulators, certainly in the State of Texas and Oklahoma and I think the same thing is true in Pennsylvania, have obligations on well operators to monitor your casing strength so you know if you had some type of a loss of integrity of the well. So the contamination of fresh water that’s occurred is unrelated to hydraulic fracturing. It doesn’t mean it’s not an issue that needs to be managed by our industry, and it is managed. But the source has largely been from incidents like that not related to hydraulic fracturing.

I think the other challenge we have in hydraulic fracture, though, is in handling these large volumes of fluids on the surface. And I think that there have been some less than what I would call best practices in the handling of these large volumes of fluid on the surface. With these, the only thing that’s different about these unconventional shale plays today from traditional tight gas procedures that were used decades ago are the size of these hydraulic fracturing procedures.

The current — when you’re talking about these multiple stages where you frac the well 20, 30, 40, 50 times, so you are injecting very large volumes of fluid into the formation. And then you produce all that fluid back out, and you’ve got to do something with it. And there’s been some handling of those fluids when they’re produced back that’s not been done as well as it could be.

If you look at the totality of the number of procedures that are carried out, though, year-to-year and you weigh that against the incidents that have occurred, it’s a very, very, very small percentage. When they happen to you and they happen on your land or your property they’re big. I’m a landowner. I don’t like it when the guys operating on my property do those kinds of things. So they’ve got to go out and clean it up.

But that’s I think our challenge is we’ve got to have better handling procedures on the fluids that we’re using so that those things don’t happen, and there are a lot of parts of the industry where recycling of those waters so we’re not using as much of the fresh water from sources either public or private, a recapturing of the fluids, cleaning them up, using them again. Now, we’re doing a fair amount of that. Others are as well.

So I think those are some of our challenges are just the size of these things. The threat subsurface I continue to believe is very low. And it doesn’t mean you don’t have to monitor and you’ve got

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to do these things properly, and if you ever sat on one of these jobs and if you ever get a chance to you ought to go out and sit on one, they’re quite fascinating.

I can assure you there is a tremendous amount of monitoring and measuring going on in that well during these procedures such that if there is any loss of integrity they know it immediately and they hit the shutdown button and everything just stops. And that’s the way we did it 30 years ago.

Yes, right here?

Question 11

I’m looking at the projected growth of natural gas of 2% globally out to 2030 and I was wondering what your thinking was in terms of United States, North America and how far can natural gas displace solid fuels in power plants? And what the outlook might be in transportation?

Rex Tillerson

Okay. Well, the growth rates in the U.S. are expected to be very significant for natural gas as well, and it is reflective in that shift between coal and gas. Our view is that given the environmental concerns here in the United States, and of course it’s true globally, that as coal-fired power plants come up for either renewal, extensions of permits, there will be a number of conditions placed on many of them from a compliance standpoint, and some of those will not make economic sense and so some of those plants will likely be retired.

The most readily available replacement is a natural gas-fired combined cycle plant. If you look at the rate of permitting of new coal-fired power plants it has tapered off in the past several years. Some plants that were in the permitting process have been pulled back. So it’s all of those factors that are occurring in the coal space that’s opening up the opportunity for natural gas to play a much larger role.

And I think the attractiveness of that from the standpoint of initial capital cost, the flexibility that natural gas power generation gives a utility, which is really important to them in load balancing, and then the fact that the resource base, I think, has now been proven to a level of confidence that power generators are now prepared to invest in new natural gas-fired generation. That’s going to lead to this uptick in demand here in the U.S. and North America.

That has been the stumbling block in the past. And those of you that have been around long enough to remember the 1970s and 1980s when we developed a big gas bubble sausage, a lot of power generation was put in and then all of a sudden the sausage disappeared. The price shot up and these guys were underwater. So there’s a concern, I think, among some of the investors in the power space as to is this shale gas production capacity sustainable? Is this for real this time? Because you told us last time it was for real and then it rolled over on us in about six to eight years.

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I think there’s a growing confidence because of the size of the shale gas resource that’s here in North America. And now more than 10 years of production history that says you can have pretty high confidence that we’ve got a long, stable, reliable supply of natural gas in this country that was missing in years past. So I think it’s a number of those factors that gives rise to this higher demand for gas in the U.S.

We have time for one last question.

Question 12

Thanks, Rex. I think you and your colleagues have done a very good job explaining your philosophy on portfolio management and asset divestitures in particular, and I wonder if I could just ask in the context of two specific recent announcements or indications how these potential transactions fit into that?

First, the decision to divest conventional gas properties in Canada pursuant to the deal with Husky. I guess selling conventional gas at this particular point in time I wouldn’t see as being maximizing shareholder value. And then also the decision to apparently seek to divest your interest in Block 31 offshore Angola?

Rex Tillerson

Well, obviously you probably — you must calculate a different value for those than we do. The conventional gas assets in Canada and Block 31 interest, all of it, it’s like every asset. We have a view of what we think the future cash flows and earnings are going to be from that asset. We’ve got a model built. We think we understand them pretty well.

And if someone wants to come in and give us more today than that value of continued operation is going to provide us over the next 20 years of the asset, we’re going to — we’ll take the PV dollars today, particularly if it’s an asset that means we have to put people on it. So some of this is not just — I mean we’ve got to get the value in dollars and cents right, but it’s also considering that we’re bringing a lot of new things into our portfolio. What are the highest value things to have your people working on?

They can’t work on — you can’t just give them six more things today to work on because they’re already working full-time on some pretty good opportunities. So it’s also in our view it’s a bit of a seriatim, if you will, on those assets that consume a certain amount of talent for what we get back from them. If we can’t get good value then we’ll keep them, but in this case we did receive good value on those relative to what we viewed the life of the asset’s value would be.

The same in Angola Block 31, it’s a question of looking at well, what do we think the future value of that, the current developments, the future plans developments, looking at the capital requirements, looking at the nature of the PSA construct over there, you can — we run a model

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on it and we say we think it has this kind of value. Does somebody want to give us that value plus above that value today then we’ve got to seriously consider doing that. And then we take the people that were overseeing our interest in Angola Block 31 and let them go work on something else that has higher value.

So it’s a lot more than just the dollars and the cents, but the dollars and cents have to be correct. And then we consider, okay, there are some real organizational positives out of this, too. We can redirect our people working on something that we think we now have that’s of higher value to us and our shareholders.

I think we’re out of time. Let me thank you all again for coming. I thank you for your questions. And I thank you for your interest in Exxon Mobil Corporation and hope you all have safe travel home.

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