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Form 8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) March 8, 2006

Exxon Mobil Corporation

(Exact name of registrant as specified in its charter)

New Jersey

1-2256

13-5409005

(State or other jurisdiction

of incorporation)

(Commission

File Number)

(IRS Employer

Identification No.)

5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298

(Address of principal executive offices) (Zip Code)

(Registrant’s telephone number, including area code): (972) 444-1000

______________________________________________________

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01

Regulation FD Disclosure

Item 2.02

Results of Operations and Financial Condition

A transcript of remarks made and questions answered by senior executives of the Registrant at an analysts’ meeting held on March 8, 2006 is attached as Exhibit 99.1. The slides presented at the analysts’ meeting are attached as Exhibit 99.2. This material is being furnished under Item 7.01.

In addition, information contained in the attached material regarding results of operations and financial condition for completed quarterly or annual periods is furnished pursuant to Item 2.02. Additional information responsive to Instruction 2 of Item 2.02 is furnished as Exhibit 99.3.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	EXXON MOBIL CORPORATION

Date: March 14, 2006	By:	/s/ Patrick T. Mulva
		Name:	Patrick T. Mulva
		Title:	Vice President, Controller and Principal Accounting Officer

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INDEX TO EXHIBITS


Exhibit No.		Description

99.1		A transcript of remarks made and questions answered by senior executives of Exxon Mobil Corporation at an analysts’ meeting held on March 8, 2006.

99.2		Slides presented at an analysts’ meeting held on March 8, 2006.

99.3		Frequently Used Terms and additional information.

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A transcript of remarks made and questions answered by senior executives

Exhibit 99.1

Exxon Mobil Corporation

Presentations and Q&A Session

Analyst Meeting

New York, NY

March 8, 2006

EXXON MOBIL CORPORATION ANALYST MEETING

MARCH 08, 2006

New York, NY

9:00 a.m. ET

Henry Hubble, (Vice President of Investor Relations and Secretary of the Corporation)

Why don’t we go ahead and get started. I would ask that just to maintain that silence, though, if you have telephones or pagers, if you wouldn’t mind turning those off so we avoid disruptions during the meeting, that would be great.

I’d like to welcome you all to ExxonMobil’s analyst meeting. And for those of you that I haven’t met, my name is Henry Hubble, and I’m the Vice President of Investor Relations and Secretary for the Corporation.

As you know, and traditionally we talk about safety, and I do need to do that this morning, too. We do have exits at the back of the room and the front of the room in case there was an emergency. Our New York Stock Exchange personnel are available to help with directions. If we do need to evacuate, just proceed to the nearest exit and the New York Stock Exchange personnel will guide you to the best way out.

I’ll draw your attention to the cautionary statements as well. You’ll find that in the front of your presentation materials and up on the screen now. This statement contains information regarding today’s presentation and discussion. And I ask, if you haven’t read it to do so now. I would also refer you to our Web site at exxonmobil.com for additional information on factors that affect future results, as well as supplemental information defining some of the key terms that we’ll be using today.

Turning now to the agenda for this morning’s meeting, we’ll begin with Rex Tillerson’s remarks on the Corporation’s performance. Then, Stuart McGill will present an overview of the Upstream business strategies and results. And then, Steve Simon will cover the Downstream and Chemicals business strategy and results. Then we’ll take a short break and we’ll keep that less than 10 minutes, if we can, so we can get everybody back here and get back to the Q&A piece. Rex will come back and do some closing remarks and summary, and then we’ll open it up for questions. We’ll target to have the meeting over at noon, and we’ll stick to that. We have some other engagements afterwards so we’ll work it that way.

And at this point, I would like to turn it over to Rex Tillerson, our Chairman and CEO.

Rex Tillerson (Chairman and CEO)

Thank you, Henry. And I do want to welcome everyone who’s joined us today for the meeting, either in person, those of you that are here, and those that are joining us by teleconference or by way of the internet. It is a pleasure to be with you, and the weather is considerably better this year than it was when we met this time last year. I do look forward to sharing our results and discussing with you how ExxonMobil is positioned to meet the many challenges of providing energy to meet the world’s growing demand. Energy remains essential to our way of life, and to economic progress.

The interest in our industry is very high right now with the rise in commodity prices, concerns about current and future energy supplies, and the focus on our company’s earnings. The current policy debates bring into sharp focus for us, how little the fundamental workings of our business are understood. The level of misinformation only serves to make the task more challenging to improve the understanding of the enormous scale of the energy markets, the limited options available in the foreseeable future, and the importance of energy supply diversity.

Notwithstanding the current public debate, the fundamental business challenges and the long-term outlook for ExxonMobil remain unchanged. The world’s energy needs are still expected to be nearly 50 percent greater by the year 2030 than they are today. Our industry remains massive, and very much a long-term capital-intensive business. Projects still require years to develop, costs billions of dollars to bring on-stream, and operate for decades.

What also remains unchanged is ExxonMobil’s approach to the business. We maintain our long-term perspective and disciplined approach to investment and focus on world class operational performance. And we continue to measure our business results in a consistent manner. This approach by ExxonMobil has lead to a history of industry-leading results, and that was the case in 2005.

Looking at those results in more detail, by practically every measure 2005 was an outstanding year. Despite serious challenges which included the hurricanes in the Gulf of Mexico, we again delivered industry-leading safety performance. This accomplishment, like most others, is due to the hard work and dedication of our world class workforce. Our net income was a record $36.1 billion representing the largest ever for a U.S. company. Return on capital employed was 31 percent, and cash flow from operations and asset sales was more than $54 billion. These financial results directly benefited our shareholders. In 2005, we returned over $23 billion to our shareholders via dividends and share purchases to reduce shares outstanding, a 56 percent increase over 2004 levels.

We also invested a record nearly $18 billion into the business last year. Our financial and technical strength, allow us to pursue all opportunities that satisfy our rigorous criteria. As a result, we continue to identify and progress a diverse portfolio of world-class, profitable investment opportunities.

Turning to the next slide, you’ll see that we achieved superior results in each segment of our businesses as well. Our industry-leading performance across the cycle is a testament to our long-term perspective, our disciplined approach to investments, and our focus on world-

class operational performance. We’ve developed a high performing portfolio of assets that provide us an advantage in scale, geographic diversity and business mix, that reduce overall risk associated with changes in commodity price, local or regional market conditions and where we find ourselves in the business cycle. On average, over the last five years, more than two-thirds of our operating income was generated from holdings outside of the United States. Our consistent approach to looking through the short-term changes in the business environment, and maintaining our focus on the long-term fundamentals in this global industry, has led to our competitive advantage.

For example, while others today are exiting the chemical business, we have grown our chemical business and generated over $3 billion in normalized earnings in 2005. Over the last 10 years, our chemical business has achieved an average annual return of 14 percent, while our competitors averaged only eight percent. Our proven long-standing business approach has delivered growth in shareholder value.

It is this consistent execution of our business approach across episodes of changes to the business environment that provides that competitive advantage. Our approach begins with investment discipline focused on long-term fundamentals in the identification of resilient projects and other investment opportunities. All investments are subjected to a rigorous reappraisal following completion and lessons learned are incorporated into future development planning processes and investment decisions. We apply the same rigor and attention to detail in our operations. Our approach to operational excellence commits our organization to operating our assets and all of the supporting business processes to the highest standards of reliability, efficiency and integrity.

In meeting these commitments, we set new industry benchmarks. Throughout the inevitable highs and lows of the business cycle, our approach has continued to deliver industry-leading returns, superior cash flow and growth in shareholder value. Simply put, it works. It is a transparent and straight-forward approach to doing business, one that is well understood at all levels of our organization, and an approach that we don’t intend to change. We don’t need to. We don’t incur the cost, financial or manpower, of refocusing our organization every few years on a new set of priorities.

Our approach is built on our core values that are firmly established throughout our globally aligned functional organization. This includes a commitment to operate to the highest ethical standards, and is supported by rigorous internal processes and systems. It’s backed by organizational discipline and leadership to ensure the business is run for the long-term benefit of our shareholders.

Organizational structures can be duplicated, but ExxonMobil’s culture, our capability and our approach are unique strengths that are not easily replicated. Over the next several slides, I’m going to step through the major elements of our business approach beginning with discipline investment.

Our investment strategy has remained consistent over the years. It is not driven by short-term swings of commodity prices or earnings. Annually, we undertake our own rigorous assessment of the underlying economic and energy trends, and develop our own view, from a country, regional and global perspective from these fundamentals required to meet

growing energy demand. In fact, I invite you to review our views which are available in our Energy Trends report.

That understanding underpins the basis on which we invest our shareholders’ money wisely in projects that remain attractive over the long-term. This disciplined approach to pursuing and selecting the most attractive investment opportunities continues to distinguish ExxonMobil. We are long-term driven, and we’re patient. And we’re not opportunity constrained.

Standing back from the annual spending patterns confirms the consistency of our approach, as we have invested over the last 15 years more than we have earned over that same period. As depicted by the pie chart on the right, our investments are geographically diverse. Our presence in all regions of the world provides us an efficient and effective platform for investing in all profitable opportunities that meet our criteria. The growing trend in capital expenditures is a direct result of the rich portfolio of investment opportunities in our inventory, our ability to mature many world class opportunities to our investment standards, and to successfully progress the execution of these opportunities.

Looking to the future, we have announced several large potential projects, that are likely to increase the spending profile towards the end of the decade, including the Qatar Gas-to-Liquids project, chemical projects in Singapore and Qatar, and the Fujian refining, chemical and marketing joint venture in China. In addition, we expect Upstream spending to remain strong with ongoing programs in mature areas, such as North America, Australia and the North Sea, as well as growth areas like the Middle East, Russia, the Caspian and West Africa. The future spending levels shown here are not targets. They are estimates based on the projects already in the portfolio at various stages of maturity.

And of course, we continue to add new attractive investment opportunities. Actual spending in a given year will vary depending upon the progress of individual projects.

A key enabler for future investments is technology. We continue to invest in proprietary technologies at levels above our competitors. In 2005, we spent over $700 million and our five year average, shown here from 2000 through 2004, exceeds $600 million per year. Our focus on proprietary technology delivers competitive advantage. It opens doors to resource opportunities through cost effective solutions for resources in challenging environments, and for frontier resources such as oil sands, tight gas, and extra heavy oil. We have earned access to resource opportunities because of our suite of technology and the capabilities of our people. We utilize our technology to develop innovative products and new and improved manufacturing processes in the Downstream and the Chemicals businesses. Our scale and functional organization structure provide us an advantage by focusing on areas of greatest potential for differentiation and rapidly and broadly deploying new technologies into the fields of application.

We balance our emphasis on technology extensions, which can be quickly implemented in our existing operations, and breakthrough research that can have a significant and lasting impact on the corporation and the industry. We maximize the value of technology efforts by integrating our research activities into the business planning process and stewarding progress similar to other performance elements in our business lines. One measure of

technology differentiation is the number of patents. In the bottom chart, you can see that we were granted nearly 2500 patents in the last five years. This is nearly double our nearest competitor, and almost as many as all three of the competitors combined.

Just as we take a disciplined approach to technology and investment decisions, the same is true of our ongoing review and evaluation of our existing assets, to ensure that they are generating the highest value for our shareholders. We regularly conduct reviews to ensure that all assets adequately contribute to our results, are aligned with our strategic objectives, and are delivering maximum value to the shareholder. Assets are divested when they no longer meet these objectives, or are worth considerably more to others. Over the last five years, asset sales have generated a cumulative after-tax cash flow of over $13-and-a-half billion and cumulative earnings of over $4-and-a-half billion. This ongoing process insures an efficient, dynamic capital base. And we work very hard to ensure we effectively maximize the value of our large retained asset base with our commitment to operational excellence.

Nothing receives more attention than the safety and health of our employees, contractors, and the people who live and work in the areas in which we operate. Our 2005 performance continued to lead the industry. We are ever mindful and aware of the unfortunate industry events that have occurred and serve as a stark reminder to all of us of the inherent risk associated with our activities, and the importance of safety.

Safe operations are our highest priority. Discipline, commitment and the effective day to day management required to achieve high levels of safety performance are the same factors that lead to overall excellence in the operation. Safe, stable and reliable operations are the sign of a well run organization and one that can maintain focus on rapidly delivering improvements. Our global functional organization strongly supports our safety leadership and overall operational excellence approach.

ExxonMobil’s ability to fully leverage our global presence and scale is facilitated by our global functional organization structure. Our ability to set priorities on a global basis, and fully draw on the organization’s wealth of knowledge and expertise to deliver superior results on a consistent basis globally is a differentiating capability that has set us apart from our competitors. Our organizational approach is built on a foundation of common standards and culture that has been created over many years. The standardized work processes, management systems and information technology infrastructure support excellence in all we do. This global standardized approach creates ongoing opportunities to capture significant cost efficiencies and business improvement. Our global functional organization armed with these systems and processes allows the right resource and technology to be deployed quickly wherever and whenever it is needed. We continue to be pleased with the benefits generated from our approach and the ability for rapid implementation of new technology and best practices throughout our global functional organization.

Let me share an example of how our global approach has captured value with our support services organizations. These are the activities that provide computing, telecommunications, real estate, controller activities - all of those various things that are required to run a business. Similar to our business lines, our support services also were organized globally at the time of the merger. Common global processes were established, and subsequently automated. This facilitated the last step of consolidating select support services activities

into cost effective business support centers. A disciplined focus on change management has been key to ensuring that while costs were reduced, the quality and reliability of services were improved.

This example may seem straight forward, however, the key to success is the initial standardization and adoption of common processes and practices before automation, which makes this difficult for others to duplicate. Since 1998, we have realized net of inflation and net new business growth, $700 million in savings, or a 14-percent reduction in support services costs. This net reduction has been captured through $1-and-a-half billion in efficiencies created by our global approach. This is one example of how our drive for continuous improvement in all aspects of our business, including cost control and productivity, are yielding results.

And there’s been a lot of recent talk about cost pressures. Cost control is critical in our industry, particularly when you find yourself at either extreme of the business cycle. It’s one thing to keep the focus on cost when you’re in a low-price environment. It is quite another to maintain the focus and the discipline on cost in a high-price environment. We’re continually working on ways to mitigate, manage, and eliminate unnecessary costs in our businesses and increase productivity. In 2005, we again delivered more than $1 billion in cost efficiencies, and we expect to deliver another $1 billion in 2006.

Our improvement initiative pipeline remains full. As you can see in this chart, we continue to more than offset inflation in our cash operating cost. Our operational excellence approach includes a relentless focus on becoming more efficient. Our productivity continues to improve at an impressive rate. Our workforce is more than 14 percent smaller than it was five years ago. While others may feel that inflationary costs are beyond their control, offsetting these costs remains front and center in ExxonMobil. And it contributes to our industry-leading returns throughout the cycle.

Return on capital employed, in our view, continues to be the best overall measure of financial performance, given the long-term and capital-intensive nature of our industry. I would be cautious, and perhaps a bit skeptical, of anyone who tries to deemphasize it. We have continued our superior performance with a five-year average return on capital employed of 21-and-a-half percent. We have widened the gap between ourselves and competition as we have captured more of the upside provided to us in the business. Our 2005 ROCE of 31 percent is nearly 50 percent higher than our nearest competitor.

We continue to focus on maximizing value from our assets and increasing our advantage through sustainable business improvements. Some seem to have focused on other metrics to guide what they view to be in the best interest of their shareholders. As I think is evident by the results of this past year, their approach, such as buying or growing volumes simply for the sake of increasing volumes, does not produce superior returns. For us, it is capturing growth and earnings for the long term while maintaining disciplined investment and operational excellence to ensure a superior performing underlying asset base.

The chart on the right is one we’ve shown you before. Our major competitors continue to write off large assets in their business. Our competitors have written off $17-and-a-half billion over the last five years, and over $29 billion over the last 10 years. This reflects again

the rigor and discipline we apply to every investment decision and our organization’s commitment to manage the assets efficiently and effectively across the business cycle. I’ll leave it to you, the analysts, to do the mental math around the effect on our competitor’s ROCE in the absence of these write downs.

Before we leave ROCE you might be wondering, why is ExxonMobil allowing the extra cash on our balance sheet to effectively lower near term ROCE? Well again, we are driven by the long-term value for our shareholders. We’re not going to sacrifice that long-term value to improve a short-term measure. We’re going to continue to take a disciplined approach to how we manage cash and ensure we maintain the financial strength and the flexibility at all stages of the cycle to pursue any attractive opportunity, particularly those of significant size and scale.

In 2005, we generated record cash flow of over $48 billion from operating activities. This is an increase of more than $7-and-a-half billion, or 19 percent, from 2004 levels. Over the last five years, our annual average cash flow from operations was $32 billion. Our current cash use rate is well above that at over $45 billion per year when you do the sums on our current Capex of about $18 billion a year, our dividend pay out of $7 billion a year, and the current level of share buy back at $5 billion per quarter. Some of you think we have a cash problem. But as with our investment approach and all aspects of this business, it is important to look at this over a long time frame, and with a context.

We do have plans to minimize the cash on our balance sheet, however, we’re going to be prudent, and we’re going to be methodical about it. We will manage our cash in such a way that we maintain financial and investment flexibility. We’re not going to invest in lower return projects. And we will not buy expensive volumes, and we will not jeopardize our ability to provide a consistent and growing dividend to our shareholders.

Before leaving to this chart, I would point to the magnitude of our numbers. Many think our cash flow is larger than our competition simply because we have a larger asset or volume base. But the real question is how efficiently and effectively do we generate the cash? In the next chart, you can see we are capturing more of the upside than our competition.

The chart shows cash flow from operating activities indexed to 2001. As you can see, our cash flow has more than doubled from 2001, while our competitors have not increased as much. Our businesses are generating more cash. These results, again, reflect the benefit of our long-term approach. We have strong performance in all business lines, and are delivering sustainable improvements throughout our portfolio. We have the financial flexibility and the strength to capture opportunities at any stage of the cycle, and our superior cash flow performance allows us to continue our strong history of growing shareholder value.

ExxonMobil delivers significant shareholder value through cash distributions in the form of dividends and share purchases which reduce shares outstanding. Since the year 2000, we have distributed $79 billion to our shareholders, with roughly an even split between dividends and the share purchase program. We have paid a dividend for more than 100 years, and have increased the annual dividend every year since 1983. Recently, we raised our quarterly dividend from 29 cents per share to 32 cents per share, a 10 percent increase. We

have increased the annual dividend on average by nine percent per year, over the last three years.

We have used the share purchase program as a tax efficient means of returning value to the shareholder by steadily reducing the shares outstanding. Since resuming share repurchases following the merger, we have purchased over 825 million shares in excess of dilution and have reduced shares outstanding by 12 percent in total, and by four percent in 2005 alone. Our program is larger and more consistent than our competitors, as you can see from the chart on the left. The reduction in shares outstanding increases the ownership of the remaining shares. Therefore, each remaining share owns more of the company, more of the reserves, more of the production, more of the physical assets, and obviously more of the earnings. The chart on the right shows the contribution from the share repurchases to earnings per share. Our 2005 earnings per share were increased by 57 cents as a result of the shares reduced since the year 2000.

We are often asked how this increased ownership benefits the remaining shareholders. The next chart describes the value of increased ownership. One way to quantify the value is to compare the growth in stock price versus the growth in market capitalization. The chart shows the shares outstanding, stock price, and market capitalization indexed to the restart of the share buyback program following the merger.

The gray area at the bottom of the chart shows the reduction in shares outstanding since the year 2000. The blue line is the market capitalization of the company and the red line is the growth in stock price. At the end of 2005, the market capitalization had increased 26 percent since 2000, and the stock price had grown 43 percent over the same period. The delta shows the benefit of the share buybacks to shareholders.

Now with that understanding of our business at the corporate level, we’re now going to turn our attention to each of the business lines. At Stuart and Steve review the respective business lines, there are a few points that I would ask you to keep in mind. First, our results in 2005 were truly outstanding. While these results were clearly supported by strong commodity prices, our business captured more upside than our competition, demonstrating the underlying strength in ExxonMobil’s business fundamentals and the value of our long-term approach.

As we move forward, we’re focused on building upon our competitive advantage. As you’ll hear described in the business discussions, we are well positioned to continue our role of effectively meeting the challenges of supplying energy and petroleum products to a growing world demand.

Now let me turn it over to Stuart for a discussion of the Upstream.

Stuart McGill, (Senior Vice President)

Thank you, Rex. It’s my pleasure to review ExxonMobil’s Upstream business with you this morning. I’ll start with a snapshot of 2005. The Upstream had record earnings in 2005, on the strength of oil and gas prices. We widened the gap with competition by recording a 46 percent return on capital employed. Annual average production was 4.1 million oil equivalent barrels per day. We had another strong year of additions to our total resource base, and to our proved reserves. Our capital spending was up by over $2 billion versus 2004, on higher levels of drilling and project activity. Before discussing the business further, let me remind you of our Upstream strategies.

We seek to identify and pursue all attractive exploration opportunities. We invest in projects that deliver superior returns. We put great focus on maximizing the profitability of the large volumes of oil and gas we produce. And we seek to capitalize on growing natural gas and power markets. Two comments before I leave strategies. They’re unchanged from last year and from the year before, and from the year before that. And I wouldn’t look for them to change next year either. And secondly, they’re not likely unique to ExxonMobil. What is unique to ExxonMobil is our ability to execute them. Enabled by our straight forward business approach, execution excellence underpins several very unique competitive advantages that I’ll describe for you today, advantages that permeate the entire asset lifecycle.

Our resource base is industry’s largest, and a source of significant advantage. This resource base allows us to continue to identify attractive development opportunities and be disciplined and patient in our quest for those opportunities. On the strength of our resource base, our project portfolio is the most attractive in industry and the strongest since establishing our global development company in 1998.

In the Upstream business, over 50 percent of total lifecycle cost is spent before production start-up. Generating industry-leading returns requires superior project management performance, and I can say with confidence that our organization is the very best in industry in executing large challenging projects. As these projects are brought online, the challenge is to maximize the value of the flowstream over the life of the asset, the responsibility of our global production company. This competitive advantage derives from a number of rigorous systems to ensure the highest level of safety and operational integrity, industry-leading cost control, best in class reservoir management, and structured asset optimization to name just a few.

The common thread through all of this is technology. Both proprietary and adapted non-proprietary technology are key to our success. And I’ll share with you later some recent examples. Taken together, these competitive advantages combined to result in industry-leading returns.

Now I’ll expand on each of these areas of competitive distinction starting with our large, high-quality resource base for the oil and gas, that in our judgment will ultimately be produced from fields in which we have the development rights. At 73 billion oil equivalent

barrels, it is the largest in industry. And as you can see from the chart, it is diverse in geographical distribution as well as resource type.

Looking to the left chart, the Americas and Europe volumes make up about half of the base. And recent growth has come from Africa and the Middle East. As you can see on the right chart, conventional oil and gas is our largest segment representing about 30 percent followed by heavy oil and sour gas resources, a significant and growing LNG business, strong arctic positions in Sakhalin and Alaska, a deep water position in West Africa, as well as a growing tight gas position centered in the Piceance Basin in Colorado.

As one example, I’ll expand on our undeveloped cold bitumen resource, part of our Canadian heavy oil position which includes Cold Lake production, and our interest in Syncrude, and the Kearl oil sands resources located in Canada’s Athabasca region just north and east of Syncrude. We have a good understanding of the resource quantity and quality through our extensive coring and evaluation work done to date. The graph on the top right shows the ratio of the total volume of overburden and ore compared to bitumen in place for a number of competing projects. A lower number provides an operating expense advantage since less material is handled for each barrel of bitumen produced.

The lower graph contrasts resource size with Kearl being the largest at 4.4 billion barrels gross, clearly sufficient to yield a material long life production flowstream. In summary, Kearl is the best of the undeveloped mining resources. We are being judicious about the development pace, and designing strategies to mitigate the overheated cost environment in the Ft. McMurray area. We will invest in this large, high-quality resource when the project is ready and robust.

2005 was a banner year for resource base additions with 4.4 billion oil equivalent barrels, as you can see from the graph on the top right. Our global exploration company is tasked with the job of acquiring rights to the world’s best resources. It is the clarity of mission and consistent pursuit combined with the global capabilities our organization brings to bear on hydrocarbon development solutions that drive the results that we had last year. Locations of the additions are shown on the map.

The largest addition was in Qatar with the signing of the RasGas III agreement for development of the large LNG trains numbers six and seven. Other important additions came in the U.S. on our Piceance Basin acreage, in Canada on the heavy oil acreage, and in the West Africa deep water. Resources were also added with acquisition of additional interest in Kashagan and with the equity alignment of the Greater Gorgon area in Australia. Finding and resource acquisition costs are shown in the bottom right, and came in below 50 cents per oil equivalent barrel last year. Over the last five years, both the quantity of the resource additions, and the competitive finding cost, position us well for continued high levels of proved reserves replacement.

We add to our resource base in basically two ways. Either by gaining access to discovered but undeveloped resources by bringing development solutions and capabilities to the resource owners, or by discovering new resources. This slide highlights a few of the higher risk, higher potential exploration activities we have underway. The U.S. Blackbeard and Norway Kogge are presently drilling. We expect to drill the Canadian Orphan and the

Kazakhstan, Ansagan tests this year, and seismic acquisition and interpretation continue on the Columbia Tayrona and Madagascar Majunga blocks. Gaining access to material opportunities such as these is important to our success in adding to the resource base. And a large high quality resource base is a key ingredient for success in adding proved reserves.

So here are the 2005 year end proved reserves for ExxonMobil and competition. Our competitor’s numbers were estimated with year end 2004 10-K filings and statements on reserve replacement in 2005. It’s not surprising that the industry’s largest resource base has yielded the industry’s largest proved reserve base. When normalizing by comparing to multiples of 2005 production, ExxonMobil proved reserves have the longest life, and our proved reserves continue to grow. Our track record at replacing production has been strong with 2005 marking the 12th consecutive year of over 100 percent replacement. The graph at the top right shows the last five.

The graphic on the lower right shows the geographic diversity of our year end 2005 proved reserves. This diversity is a strength given the global spread of our future production flowstreams.

Moving now to the next of our competitive advantages - a direct beneficiary of a large, high-quality resource base—our attractive project portfolio. The next four slides summarize our current major project inventory in order of start up date. First, those projects that started up last year. All operated projects and the joint ventures in Qatar started up on or ahead of time and close to budget costs. The Kizomba B project started up well ahead of the plan, demonstrating the effectiveness of our “Design One, Build Multiple” strategy. Sakhalin-1 started up on time and within 10 percent of unit cost expectations. I’ll talk more on Sakhalin in a moment. This year’s planed start-ups show red dots on the overlay, with the 2005 start-ups changing to gray dots.

A couple of comments. The deep water Nigeria Erha field will start up this month. We expect this operated project, along with the Erha North satellite utilizing the same FPSO, to be producing near 200,000 barrels per day gross by year end. Also in Nigeria, we’ll be starting up the East Area Additional Oil Recovery project that will add 120,000 barrels per day gross production while also substantially reducing gas flaring offshore Nigeria.

The Gulf of Mexico deep water Thunder Horse development is expected to start up this year after about a year delay. In total, we expect eight start-ups. These projects, along with the full year production of the 2005 start-ups, underpin our confidence in production capacity growth in 2006.

We anticipate 14 starts-ups in the 2007-2008 timeframe, including three LNG trains in Qatar. In 2007, the 4.7 million ton per annum RasGas train five will start up. And in 2008, we will have two of the large, record-setting 7.8 million ton per annum trains starting up, Qatargas train four and RasGas train six. Combined, these projects will add over three billion cubic feet of gross gas sales, with our share being 30 percent.

There will be continued developments offshore West Africa, including Kizomba C, yet another world-scale project on Block 15. In the Caspian region, the first Tengiz expansion will come online and phase three of ACG in Azerbaijan will begin production.

Several North Sea projects will start up. In the U.S. we’ll see continued activity in bringing on Prudhoe Bay satellite fields, and the first phase of the Piceance Basin gas project, which ultimately could yield some 35 trillion gross cubic feet of gas.

Looking out to 2009 and beyond, you can see the many projects that we are progressing. There are too many to mention each individually, so let me make just a few broad comments here. The portfolio includes large projects in the U.S. with Alaska Gas and Piceance, and Canada with Mackenzie gas and Kearl oil sands, as well as numerous projects in the mature North Sea. We have a strong presence in growing areas offshore West Africa with our deepwater Angola and Nigeria projects. We are co-ventures in the large Caspian area projects of Tengiz, Kashagan and ACG.

In the Middle East, I already mentioned several of the LNG projects in Qatar and there are others listed here for 2009 and beyond. In Asia Pacific we’re working on the PNG gas pipeline project, the Greater Gorgon LNG project, and of course, further phases of Sakhalin-1. In total there are 62 projects depicted on this page, representing well in excess of two million net oil equivalent barrels of daily production.

Just about any way you slice it, we have a diverse project portfolio, geography, resource type, basin maturity, fiscal regime, et cetera. I think you can see how this provides a measure of risk mitigation. This strong position allows us the ability to ensure the right project is brought online at the right pace, for optimal resource development, for the benefit of both the resource owner and ExxonMobil shareholders. For example, we set a new record for cycle time on Kizomba B. Whereas at Sakhalin we chose a multi-phased project, which allows us to incorporate early experience into later phases, and utilize a common infrastructure.

Before leaving our project portfolio, let’s look at the total inventory of both major and minor projects. And then, we’ll look at the nature of the production flowstreams that are expected from this inventory. This chart shows our total project inventory from 2001 to 2005 by maturity level from the early planning phase at the top of the bars, to the start-up phase at the bottom. You can think of this as projects coming in at the top of the bars, working their way down through the various project phases until start-up.

The project inventory at the year-end 2005 will develop some 26 billion oil equivalent barrels net to ExxonMobil and underpin our reserves replacement in the coming years. Our rigorous project-management system ensures readiness before full funding. Looking at the projects in the inventory that have reached at least the designing phase. We continue to expect gross unit development costs at about $3 per oil equivalent barrel. The key to this is selecting development concepts and technologies that are fit-for-purpose, designing execution strategies to mitigate risks, and proactively managing activities throughout the course of the execution.

Through our many interactions with our other operators and joint ventures, it’s clear to us that our development company sets the standard in the delivery of new developments on time and on budget.

Now to the nature of the production flowstreams that are expected from this inventory of projects. This chart shows the production capacity build-up from our major development projects to start up from 2005 through 2015. The bars are divided into two segments. On top are the projects that deliver typical decline flowstreams. They reach peak rates fairly quickly, hold about level for a few years, and then go into decline. Examples are Kizomba B, Erha and Thunder Horse. The bottom segment consists of projects that exhibit a very different production profile. These projects have long production plateaus, as long as 20 to 25 years in many cases. Generally, these profiles are associated with very large fields or resources where production rates are typically limited by a facility or infrastructure capacity. Examples include the RasGas and Qatargas projects, the Kearl heavy oil projects and Kashagan. Nearly two-thirds of the anticipated new production over this period is from projects exhibiting these long production plateaus. By 2015, 80 percent of the expected new production will be coming from such projects. This compares with about 15 percent of our production today. This is an important consideration in our confidence in growing production capacity in the future.

Now with that understanding about project portfolio, I’d like to turn to execution of these projects. This is an extremely important capability, as the industry ramps up activity to meet growing oil and gas demand worldwide. With the high activity level, there is intense pressure on capital efficiency. This is an area where ExxonMobil excels and is growing the gap with competition.

Shown here is an indicator of performance in the current environment. It looks at relative performance of operated projects. We selected all of the very large projects greater than $1 billion that have either recently started up or will do so within the next three years. Wood Mackenzie cost and reserve data were used, updated with more recent public information or project owner data. The graph on the left shows that our very large operated projects have considerably lower unit development costs than our competition. Equally distinguishing is the graph on the right, which shows the cost increases that have become apparent for this group of projects over the last 12 to 18 months.

We’re all facing the same cost environment. Yet through careful management of project costs and identification of offsetting cost reductions, we have minimized the impact on ExxonMobil operated projects. This is just one example of our differentiating project management capabilities. It is confirmation that our global functional development company with the rigorously applied project management system is able to better execute large projects.

Let’s take a look at three examples. One suite of projects that demonstrates our project execution abilities is in Angola deepwater Block 15. The plot on the left shows the production build up from these projects, along with our planning basis back in 2003. With the novel Early Production System deployed for Kizomba and the “Design One, Build Multiple” concept used for Kizomba A and B, the project execution for Block 15 has set a new industry benchmark. Consolidating our years of project management experience within one organization has given us the ability to take sound concepts like these and apply them to

a very large inventory of very large projects, where strong performance yields a lasting competitive advantage.

The development concepts for Kizomba A and B are somewhat unique, in that tension leg platforms are used in conjunction with FPSO’s to allow cost effective well intervention over the life of the field, thereby lowering total field costs. Activities on Block 15 are continuing with Kizomba C where we’ll deploy two smaller FPSO’s to optimize development costs given the distance between fields. And additional sub sea developments are under consideration to utilize FPSO ullage as it becomes available.

At Sakhalin-1 we’ve used our drilling expertise to economically develop the offshore Chayvo Field from an onshore location, reducing the required investment, accelerating first oil, and reducing the environmental footprint.

As can be seen on the graph on the upper left, these Chayvo wells established a new industry benchmark for horizontal displacement for the vertical depth drilled. The bottom hole locations in these wells are over five miles laterally displaced from the service location.

Now to put that in perspective for you. It’s like spudding a well right here in the New York Stock Exchange, and hitting a target about 20 feet tall, that’s two miles beneath the Metropolitan Museum of Art. The graph below shows that the drilling rate of penetration in feet per day, and again, these wells have established a new benchmark. First oil and gas was achieved at Sakhalin on October first of last year with an early production system. The permanent production facility is under construction with a target completion date of year end 2006. With this facility online, gross oil production capacity will be ramped up to around 250,000 barrels of oil per day. Current sales are about 45,000 barrels of oil, and 95 million cubic feet of gas per day. We’re pleased with the Early Production System performance and the outlook for phase one. Planning continues for a gas export project as well as future oil production phases.

A third example is Qatar LNG where we’re participating with Qatar Petroleum in several large projects to efficiently develop the North Field, the world’s largest non-associated gas field. This world-class reservoir and ExxonMobil capabilities have combined to capture the economies of scale potential, making Qatar LNG cost competitive worldwide, including to the large mature gas markets of Europe and the U.S.

The worldwide evolution in capturing scale and the step change for the 7.8 million ton per annum Qatargas II and RasGas trains is depicted in the upper left hand chart.

As the lower left graph depicts, these large-train developments in combination with new-generation large LNG ships and terminal efficiencies have resulted in a unit cost reduction of more than 25 percent. On the right is shown the capacity and start up timing of the ExxonMobil and Qatar Petroleum LNG projects. All funded trains are under construction, and are on schedule and budget. By 2010, ExxonMobil will be participating in 60 million tons per annum of LNG capacity, or over 20 percent of the expected worldwide market.

To round out my discussion on project management, I want to share with you ExxonMobil’s pursuit of gas markets, and a select power opportunity. ExxonMobil sells natural gas in 25

countries, and across five continents. Our ability to integrate advanced technologies across the gas value chain and our market presence and knowledge provide a substantial competitive advantage in this growing business. LNG terminals are progressing in Italy, the U.K., and the U.S. Gulf Coast that are integral to the Qatar LNG projects that I just discussed. A Hong Kong terminal is being pursued to support our power business there.

In North America, there’s been encouraging progress over the last year on the two large pipeline projects to bring artic gas to the lower 48. In Canada, the 1.2 billion cubic feet a day Mackenzie Valley Pipeline has entered the public hearing phase. In Alaska, we reached agreement with the state administration on the mature provisions of a gas fiscal contract, that would provide the predictable and durable fiscal structure needed to further progress the four-and-a-half billion cubic foot a day Alaska Gas Pipeline project. Once finalized, it will move next to public and legislative review.

In Australia we’re in FEED (front-end engineering and design) on the Greater Gorgon LNG project. This multi-field sub sea development will feed two five million ton per annum LNG trains on Barrow Island. We’re also in the final stages of FEED and are securing firm gas sales commitments for the 500 million plus cubic feet a day Papua New Guinea gas pipeline project to Australia. In Sakhalin, we’re progressing pipeline sales negotiations targeting northeast China and Japan.

LNG projects are progressing for Angola and for Nigeria. We’re also pursuing a related power project. I just spoke of the Qatar LNG business. We’re also working on a second phase of the Al Khaleej pipeline gas project. And earlier, Rex mentioned our potential Gas-to-Liquids investment. We’re conducting preliminary engineering for a GTL project in Qatar utilizing our proprietary AGC 21 gas conversion process. We continue to pursue commercialization of the large 40 trillion cubic feet Natuna gas resource. We’re evaluating the possibility of both pipeline, and LNG sales in Southeast Asia.

Now I’ll move to ExxonMobil’s distinctions in maximizing value from production assets. Looking first at a competitive indicator of performance. The graph shows earnings per oil equivalent barrel of production for selected companies. We have consistently led competition in this indicator of value extraction for the assets under management. In 2005, our lead widened. Our earnings per barrel were some 29 percent higher than the average of competition. The gap grew in a year of strong prices. So how have we performed over a range of price environments?

The right side of the graph plots ExxonMobil quarterly earnings for the past six years versus a simple weighted hydrocarbon market price. The straight line regression shown has a high correlation coefficient. In other words, we delivered the benefits of the higher price environment to our shareholders. This was accomplished by rigorous cost control and by maximizing the economic recovery from our producing fields.

One of the ways this is done is through ongoing high-quality drilling programs that are enabled by a state of the art geologic and reservoir modeling technologies. These quality drilling programs both improve recovery and test outer field limits. The graph shows cumulative production adds from our 2001 through 2005 non-project development drilling programs. In 2005, the combined contribution of these was over 900,000 oil equivalent

barrels per day of profitable production. This went a long way towards mitigating base decline. Since the infrastructure is already in place, the incremental production from these wells is typically very attractive. Listed on the right are several other parameters related to this activity. Over $2 billion per year of investment yielded significant production and improved reserve additions.

Maximizing economic hydrocarbon recovery from production assets is a key distinction for ExxonMobil. One way this is accomplished is through a suite of technologies called EOR or enhanced oil recovery. With EOR, we are typically injecting a chemical, a light hydrocarbon and/or heat to improve the mobility of the oil in the reservoir. At ExxonMobil we systematically evaluate all material reservoirs on a periodic basis for opportunities to apply improved recovery techniques, to maximize economic hydrocarbon recovery.

One of the tools that we use is our proprietary next generation reservoir simulator, EM Power. There are vendor reservoir simulation tools available to all companies, but none match the capabilities of EM Power. When conditions are ripe for an EOR project, we have the experience and technical capability to identify and implement all types of these projects. This capability is one reason the Abu Dhabi National Oil company selected ExxonMobil to enter into final negotiations for a working interest in the super giant Upper Zakum field with approximately 50 billion barrels of oil originally in place.

Another way we maximize the value of our assets is by recognizing when they may have more value to another company than to us. As with most other aspects of the business, we do this in a structured way, managed by a group of experienced professionals who ensure asset valuations are performed on a consistent basis, and that we keep abreast of trends in the marketplace. Over the last five years, we’ve sold what would have amounted to about two percent of our 2005 annual average production, and year end proved reserves. As we’ve said many times, these were lower profitability assets with limited upside potential.

The graphs on the lower left show the higher opex and lower reserves to production ratio for the divested assets, as compared to the balance of the portfolio. The environment in the last two years has allowed us to realize full value for these divested properties.

All of what we do, and the competitive distinctions we have, are the result of the integrated capabilities of our people, enabled by clear responsibilities, sound systems and the development and deployment of proprietary technologies.

A few examples that are impacting business results today, we’ve been working on multi-zone stimulation for some time, as part of our breakthrough research program. And our confidence in developing enabling technology has allowed us to acquire a significant acreage position in the Piceance Basin in Colorado. The low permeability rock containing gas requires fracture stimulation to produce at commercial gas rates. Historically industry has had little capability to economically ensure that all gas bearing segments of the formation receive equal treatment. The better quality rock would end up receiving most of the stimulation, leaving many portions undrained, which limited overall recovery. Our technology allows us to quickly and economically fracture and stimulate each gas bearing zone to boost gas recovery per well drilled.

Shown in the graph in the lower left is the difference this technology is making. It shows cumulative production versus time for ExxonMobil’s multi-zone stimulation technology versus typical industry practices. We are routinely using this technology to effectively and rapidly stimulate the 40 to 50 reserve targets that are commonly found in our Piceance Basin wells. Multiplied by the thousands of wells it will take to develop a resource such as the one on the Piceance Basin, you can imagine the enormous impact of this technology. With this completion advantage, the deployment of Fast Drill that I’ll talk about in a moment, I’m very optimistic that we’ll capitalize on our strong Piceance acreage position and develop a world class gas field that will help supply natural gas to this nation for a long time.

We announced our Fast Drill Processes last year. This process allows us to drill wells up to 35 percent faster, by increasing the rate of penetration, or ROP, by as much as 100 percent during on-bottom drilling operations. Faster drilling translates to lower costs. This process takes science to the drilling rig floor. Real time measurement of the mechanical specific energy, contrasted to that from the physics of rock failure mechanisms, enables our drill teams to make the necessary adjustments to improve performance and drill faster.

This is the industry’s first ROP design process. Understanding the physics is not new, but Fast Drill is. Our engineered process ensures that we maximize the benefit of this newly available real time measurement, bringing our global technical strength to bear on all parameters limiting rate of penetration.

Standalone technology development provides competitive advantage. But additional distinction is gained from our integrated multi-discipline approach, to technology application that spans the upstream lifecycle. Much of our success begins with developing a clear understanding of the subsurface of the earth using our proprietary seismic acquisition and processing technologies. During the early production period, we learn more about the geology of the reserve using a powerful package of new technologies and work process we call Reservoir Evaluation Time Reduction. We obtain feedback that allows us to quickly refine our geologic model. The impact of integrating this set of leading edge technologies is improved accuracy in the prediction of reservoirs performance, which provides us with clear economic options.

I’ve all ready mentioned that our physics-based Fast Drill Process is reducing drilling costs and our application of Enhanced Oil Recovery is maximizing recovery. We pursue technology advances to position us at the forefront of industry in commercializing resources.

Our goal is to maximize value through integration across the upstream lifecycle, from new concepts for finding hydrocarbons, all the way to maximizing recovery from fields that have produced for decades.

Now turning to our production capacity outlook. I spoke earlier about our robust inventory that will underpin volumes in the timeframe shown on the chart. The segments show the geographic diversity. The Americas and Europe declined modestly notwithstanding continued project activity that moderates the decline. Growth is driven by deepwater West Africa projects, the Russia/Caspian large field developments, and the Qatar LNG projects in the Middle East. Overall, this chart shows the capacity added as a consequence of our

expected level of quality project implementation. However, I’ll give you the same qualification you’ve heard previously. The actual volumes produced might well take a lumpier path, due to variables such as weather, geopolitics, regulatory changes, and oil price. This outlook does not assume any material asset divestments going forward.

That said, the competitive advantages I discussed today are very relevant to achieving long term production capacity growth and industry-leading financial performance. We’ve consistently led industry in return on average capital employed, perhaps the best single indicator of company performance in this business. It takes into account volume performance, project execution, cost management and investment decisions. But as Rex mentioned earlier, it doesn’t take into account the investment write offs that our competitors have taken. On this measure, we have a substantial lead, and it’s growing. In 2005, our return on average capital employed was 40 percent higher than the competitor’s average, and grew in a strong price environment. Our strategies and competitive advantages are equally relevant throughout the full cycle of commodity prices.

Allow me to wrap up the upstream component today with a restatement of ExxonMobil’s competitive advantages. The industry’s largest, highest quality, and most diverse resource base. An inventory of attractive projects, sufficient in size to deliver quality reserve replacement for the next decade or more, a distinguishing project management performance, a continued dedication underpinned by rigorous management processes to ensure maximum value from production assets, and finally, leading edge proprietary technology development and deployment. These advantages are allowing us to grow the gap with our competition.

Thank you for your attention. I’d like now to turn over the podium to Steve Simon who will review our Downstream and Chemical businesses with you.

Steve Simon, (Senior Vice President)

Thank you very much Stuart. And it is indeed a pleasure for me to have the opportunity to discuss ExxonMobil’s Downstream and Chemicals businesses. Let’s start off with the Downstream. In the Downstream, we also had record financial performance in 2005 with earnings of $8 billion generating our best ever return on capital employed at 32 percent. We capitalized on the strong industry environment with record refinery throughput of 5.7 million barrels per day, and petroleum product sales of 8.3 million barrels per day our highest since the merger. Excluding the impact of U.S. hurricanes, our throughput would have been up over one percent year-on-year. These results were underpinned by continued operational excellence.

Our safety and environmental performance, reliability and energy efficiency were all in-line with or better than our 2004 record performance. Finally, we again delivered over $1 billion of after tax self help through operating cost efficiencies and margin enhancements, both key elements of our Downstream strategies outlined on this next slide.

Our overarching objective for the Downstream is to deliver long term sustainable growth in shareholder value superior to that of our competition, regardless of the margin environment. To achieve this objective, we focus on the strategies listed, namely best in class operations, quality, valued products and services, industry-leading efficiency and effectiveness, integration with our other businesses, selective, resilient investments with advantaged returns all underpinned by leading-edge technology.

When you break these strategies down into components, they tie right back to our basic business approach. Our global scale and integration creates significant structural advantages. With respect to project execution, we lead the industry in project efficiency and cost, developing and implementing projects at seven percent lower investment than the industry average. Our relentless focus on operational excellence creates significant competitive advantages in raw material flexibility, margin enhancement, operating efficiencies and asset utilization. Again, all underpinned by technology leadership. And when you wrap all of these components together, they consistently deliver industry-leading returns. I’d like now to focus more specifically on each of these components, starting with global scale and integration.

ExxonMobil is the largest global refiner with interest in 45 refineries throughout the world. In addition, we are the largest global supplier and marketer of petroleum products. We are the largest manufacturer and marketer of lube basestocks, and the largest producer of basic chemicals, such as polyolefins, benzene and paraxylene. And when you combine this global scale and integration among these businesses, you create structural advantages that are extremely difficult to replicate, as I will describe on the next few slides.

For example, our average refinery size is 65 percent larger than the industry average as shown to the left, giving us significant economies of scale. In addition, over 75 percent of our refining capacity is integrated with lubes and/or Chemical as shown in the middle chart, giving us significant product yield and cost advantages. The chart on the right shows that we not only have more capacity than our competition, but this capacity is also broadly

positioned geographically. We have a strong position in mature markets, but importantly also have a significant presence in Singapore, for example, positioning us well for projected future demand growth in that region. And these structural advantages also extend to our marketing business lines.

We are the largest global supplier and marketer of petroleum products. We leverage this scale along with our integration with refining to take advantage of a broad spectrum of customer channels. Our global fuel sales are optimally distributed among retail, industrial, and wholesale, aviation and marine, and finally, supply sales direct from our refineries. Having well established access to all of these channels allows placing products in their highest value disposition.

And we capitalize on similar advantages in our lubes business. Like fuels, we are the largest manufacturer and marketer of lube basestocks. Our interests include 14 lube refineries, and 52 blend plants around the world. Nearly 80 percent of our lubes manufacturing facilities are integrated with refining, providing significant cost efficiencies and product yield advantages. We are also a leader in marketing finished lubes capitalizing on strong OEM relationships, with leading light and heavy duty equipment manufacturers, such as Toyota, Daimler-Chrysler, Porsche, Mercedes Benz and Caterpillar, just to name a few. These customers trust us to delivery technically advanced superior products. For example, our industry-leading Mobil One motor oil.

Now I’ll focus on how we leverage these Downstream structural advantages to generate self help improvements starting with economic capacity growth. The top chart illustrates that our global refining distillation capacity has grown by 50,000 barrels per day per year over the last decade. Similarly, the bottom graph shows that our global conversion capacity has grown about 35,000 barrels per day per year over this same period. But most importantly, this growth has been very attractive, achieved economically with disciplined capital investment. Advanced technology in fractionation, catalysis and coke morphology has allowed us to de-bottleneck our capacity at a fraction of grass roots cost. Consequently, this capacity growth remains economic and resilient over a wide range of industry margin scenarios. Many have asked why we don’t build new refineries. Well our capacity growth rate is equivalent to building one new refinery every three years, but at a small fraction of the cost of a new build.

We’re not just growing our refining capacity, we’re also utilizing our capacity better than competition to generate margin, and that’s shown on this next slide.

The left chart illustrates that our challenged crude runs are up over 60 percent since 2000. Challenged crudes are those which are discounted in the marketplace, for reasons other than being just high in sulfur or heavy, such as being high in acid, hydrogen or heavy metals making them difficult to process. In fact, last year, our refineries ran over 125 crudes that were new to our individual refineries, 21 of which having never been processed by ExxonMobil anywhere before.

The middle graph shows that we have increased our average global crude sulfur nearly eight percent since 2000. We have also heavied up our crude slate over this same period, of course the lower the API gravity, the heavier the crude. This raw material flexibility has

allowed us to take advantage of the recent, wide light-heavy and sweet-sour crude differentials, which results in lower raw material costs and more money taken to the bottom line.

The right chart illustrates that our clean products yields, that is yields of motor gasoline, and distillates are better than industry, and would have been even higher in 2005, if not for the Gulf Coast hurricanes. Many of the tools and technologies we use to increase raw material flexibility and optimize the product streams that move through our refineries and chemical plants have been developed and enhanced as part of our molecule management program.

As part of this program, we have developed molecular finger printing technology that enables better understanding of the key characteristics of crude beyond just the physical which are well understood right down to the chemical molecular make up. This, in turn enables more precise selection and blending of crudes with properties that maximize yields of high value products, and chemical feedstocks, while at the same time increasing utilization of lower cost crudes. Similarly, we have developed technology and advanced process modeling, which we combine with our process control and optimization tools, and our scheduling and blending best practices, to realize the highest value for each product stream. As best we can determine, no one else in industry is positioned to replicate these advantages any time soon. And the benefits are significant. We estimate the associated benefits at more than $750 million per year before tax, when leveraged across our refinery network. And this is up from the $500 million incentive we mentioned last year as we continue to identify additional opportunities to this leading-edge technology. As you can see, we have all ready captured nearly $550 million per year or 70 percent of the identified prize.

In addition to capturing more margin, we also operate our refineries more efficiently than our competition. The left graph illustrates how we are positioned on energy efficiency versus the rest of industry. Energy accounts for a little over half of our refining cash operating costs. In 2005, we had our best ever energy efficiency. And we have been improving our energy efficiency at a rate about twice that of the industry average. Our disciplined global energy management system is driving this performance, with more than a $1 billion of pre tax savings identified since its inception in 1999, equal to about 15 to 20 percent of the total energy consumed in our refining and chemical facilities. And to date, we’ve captured about half of the identified prize.

As you can see in the middle graph, our workforce continues to decrease as we improve productivity, extending our lead over industry. Workforce costs constitute about one fourth of refining cash operating costs. As a result, our unique cash costs are significantly lower than industry as shown to the right. Ours have been trending downward over the past few years, while industry has been trending upward. We’ve accomplished this in an inflationary environment, where, for example, over the least three years, our skilled labor costs are up 20 percent, our cost of chemical are up 35 percent, marine dry cargo rates have increased 50 percent, and our catalyst costs have increased 60 percent. In addition to operating our refineries more efficiently, we’re also utilizing our refining assets better than our competition.

The left chart illustrates our focus on unit reliability and its impact on refining throughput. Our unplanned capacity loss, shown in yellow, has dropped about 30 percent since 2000.

Improving reliability, of course, lowers unit operating costs and results in increased throughput shown in green.

The right chart shows that we have higher refining utilization in industry allowing us to take better advantage of the recent strong margins. And in fact, our utilization would have been significantly higher in 2005, well above 2004, if not for the Gulf Coast hurricanes, and again, our advanced technology is paving the way. For example, our disciplined reliability and maintenance management system is helping to drive this performance. Since its inception in 1994, we have not only reduced maintenance down time by 40 percent, but have also reduced maintenance cost by 30 percent.

Our self help improvements are not just limited to our refineries. We are delivering significant self help in our marketing business lines as well. For example, in our retail business, starting on the left, we continue to divest underperforming retail sites shown in red, down 15 percent since 2001. As a result of this high-grading, fuel sales per site have steadily increased up over five percent over this same period shown in blue.

The middle chart illustrates growth in nonfuels income, through increased sales convenience products, expansion of strategic alliances, and additional revenue from high margin activities such as car washes. Perhaps the best indicator of our overall retail progress is the breakeven fuels margin shown to the right for the U.S. market. This indicator nets nonfuels income against the cost of operating the site to determine the minimum margin we must make on fuel sales to breakeven. This parameter sums up the combined results of our strategy to reduce costs, grow nonfuels income, and eliminate under performing sites. As you can see, since 2001, we have lowered our U.S. breakeven margin by nearly 20 percent and our global results are comparable.

We’re seeing similar results in our lubes and specialties business. The left chart illustrates the progress we have made in simplifying our lubes business driving down costs. We have significantly reduced the number of employees, blending plants, order centers, and product formulations over the past five years.

The middle chart illustrates our success in growing finished lube sales in our key growth markets. Our lube sales in growth markets have increased over 40 percent during this same period, a rate well above the rest of industry. And the worldwide growth of our high margin flagship products, for example, Mobil One has been even more pronounced shown to the right, out pacing industry by a considerable margin. And again, technology is leading the way.

Speaking of technology, maintaining our leadership in developing and rapidly deploying new technologies underpins all of the self help initiatives I’ve described for the Downstream. I realize this chart is a bit busy, and I certainly don’t plan to cover the details, but I do think it serves to illustrate that we have a very robust array of research programs directed at achieving our strategic Downstream objectives, namely, improving raw material flexibility, lowering costs, and increasing the yield of high value products. Time doesn’t permit discussing the various R&D program shown, but as you can see, we have a lot of opportunities in the pipeline. And based on historical experience, we would expect a

sizeable number of these programs to pay dividends, ensuring sustained delivery of self help improvements well into the future.

So how does this delivery of self help improvement translate in the bottom line results, and in turn competitive advantage? Our total Downstream earnings have increased from $3.4 billion in 2000 to a record $8 billion in 2005. Obviously, the higher industry margins in 2005 provided a significant help to earnings. And our focus on operational excellence, allowed us to take full advantage of those higher margins. But this margin improvement alone, does not explain our 2005 earnings performance.

In fact, cost inflation and Forex impacts eroded earnings by nearly $3 billion offsetting a significant portion of the industry margin gain. The more significant element is our ability to consistently deliver self help improvements, on average, $1 billion per year after tax over this period. And we believe our unique global scale and structural integration combined with our steadfast commitment to advance technology will enable us to continue delivering self help and earnings growth at a pace faster than our competition as we’ve done in the past.

This chart illustrates how we are differentiating ourselves in the Downstream. The chart at the top left shows the results of our capital discipline. We have maintained a relatively flat capital base, over the past five years, despite the significant investments required to meet mandated new product specifications. In contrast, both Shell and BP have increased their capital employed, largely through new investments and some acquisitions during this same period.

The chart on the right, illustrates the results of our self help improvements. The bars represent reported earnings, and as you can see, we’re generating higher earnings than either Shell or BP even with a flat capital base. The chart on the bottom summarizes the bottom line return on capital employed results. Our Downstream approach is delivering consistently superior returns for ExxonMobil shareholders. And as previously mentioned, our opportunity pipeline is full, which we believe positions us well to further increase our lead over competition as we move to the future regardless of the Downstream margin environment.

Now let’s turn to Chemical. Our Chemical business also had an outstanding year, earnings of $3.9 billion topped last year’s record of $3.4 billion representing the highest in our history, and the highest every among oil competitors. Return on capital employed of 28 percent was the highest since 1995, and significantly, higher than any of our traditional competitors. Our global scale, integration with the Upstream and Downstream and expanded feedstock flexibility continued to provide competitive advantage. And we successfully enhanced margins despite record high feedstock costs. At the same time, our Chemical business achieved best ever results in contractor safety, reliability and energy efficiency.

Capital expenditures totaled $654 million as we continued to selectively invest in high return efficiency projects, low cost expansions of existing facilities, and growing our less cyclical highly profitable specialty businesses. Our Chemical performance is the result of proven long-term strategies which have produced continuous growth in earnings, while delivering industry-leading returns.

ExxonMobil made a decision many years ago, that the Chemical business is an important and growing part of our corporate portfolio. Our strategies have been tested and proven successful over the decades, spanning several different business cycles. These strategies include a differentiated portfolio of global businesses, well positioned to take advantage of integration synergies with other businesses. A relentless focus on manufacturing excellence, featuring cost and reliability leadership. Disciplined, selective investment in advantaged projects. And consistent with the theme you’ve heard throughout all underpinned by superior technology, which we view as a significant source of differentiation. These strategies drive our decisions and ultimately our results. And they also form the basis of our business approach.

Our Chemical business model is made up of a number of key components shown on the chart. It begins with a portfolio of products that is unique versus competition. The closest overlap is with a chemical only competitor. And even then, we estimate only about a 50 percent overlap. Our businesses are global in scope and scale, critical to serving growth in developing economies. Nearly all sites are co-located with our Downstream operations, enabling huge integration benefits in the hundreds of millions of dollars each year.

We pursue only those projects, which are advantaged versus competition as a result of our technological capabilities, know how, or broad product and market expertise. In an industry subject to ongoing margin pressure, relentless focus on operational excellence is critical to our success, yielding competitive advantages in asset utilization, cost management, utilization of advantaged feedstocks and production of premium products. And underpinning all of these components is our leadership in developing and rapidly deploying new technology. It is the successful execution of each of these components in combination that consistently delivers industry-leading returns. And I’d like now to cover each of these components in more detail starting with our unique portfolio of businesses.

Our unique mix of businesses plays to our strengths. In fact, we rank first or second in over 90 percent of our businesses. We also take a balanced approach to our portfolio, pursuing profitable growth in both commodity and specialty products.

Earnings from our specialty businesses, which range from butyl rubber to plasticizers, are shown in blue. These businesses provide a consistent, strong earnings base and have historically provided a two percent uplift to our returns over a full cycle. In 2005 our specialty businesses contributed nearly 740 million dollars, up five percent from 2004. We expect our specialties portfolio to continue providing consistently strong earnings in the future.

The red bars show earnings from higher volumes, yet more cyclical commodity businesses. Although impacted more in the down cycles, these businesses provide significant earnings in the up cycle. Driven by strong volumes and margins, earnings from these businesses during 2004 and 2005 were over three times higher than in 2003 a more typical year.

But our leading financial performance is derived from more than just our business portfolio. Capture of integration synergies is another key differentiating factor versus competition.

Although ExxonMobil maintains a separate functional company to focus on management of our Chemical portfolio, we are at the same time, highly integrated with Upstream and Downstream operations enabling capture of synergies throughout the value chain. Synergies with the Upstream relate to accessing advantaged gas feedstocks. On the Downstream side, synergies are created through exchanging feedstocks between our refineries and chemical plants. In the largest complexes, more than 60 feedstock streams are exchanged on a continuous basis.

We have developed and continued to enhance optimization tools to realize the highest value of the various streams moving through our refineries and chemical plants. These optimizations are run on a real time basis through coordinated planning activities, not easily duplicated without joint ownership and co-location of refining and chemical facilities. Joint ownership and co-location also enable energy and utilities usage to be optimized across the entire site.

Beyond the physical integration of the streams and processes, we also share laboratory, engineering and other services at joint sites. Common maintenance, inspection and reliability processes are used, and research and technology developments are jointly shared. These integration synergies have delivered significant benefits, and the benefits continue increasing each year. In fact, if you look at just the past four years, we have grown chemical and refining synergy benefits by over a-half billion dollars before tax. And we expect to continue growing these credits annually.

Integration synergies are also a key ingredient in the major growth projects that we’re pursuing.

Over the next ten years, we expect some 55 percent of the world’s petrochemicals growth to occur in Asia, over one-third in China alone. By 2015 we expect Asia will account for 45 percent of global demand for key commodity products and China alone will represent 25 percent.

We have a large, existing advantaged asset base in the Middle East and Asia that is ideally positioned to serve these growing markets. These investments are based on long-term competitive advantages, including integration with other operations, advantaged feedstocks and market access.

In addition we are pursuing major projects in China, Qatar, and Singapore to provide additional advantaged capacity to profitably meet future demand in this region. Each project has unique characteristics and is in a different phase of development.

Fujian is a fully integrated, joint project with the Downstream. It is the only fully integrated project in China with foreign participation. Qatar is a petrochemical complex that would include a world-scale cracker and ethylene derivative units. Singapore is a second steam cracking train, integrated with an existing complex, and would also include derivative units. I’ll provide more specifics on this project in just a moment.

Based on these overall plans, we would anticipate increasing our capacity in Asia/Middle East by nearly 50 percent over the next several years. In contrast, our traditional competitors tend to start from a smaller base and have less ambitious growth plans. And although Shell and BP are investing in China, it is noteworthy that neither facility is integrated.

So we are targeting not only to maintain, but in fact grow our lead over competition in this key market. To better illustrate our project plans, I’d like to further discuss our Singapore project.

Singapore is strategically located for a supply of high growth markets in Asia, especially China. Our existing plant is highly integrated with refining and is considered best-in-class manufacturing operations. Feedstock from the refinery as well as from the chemical steam cracker supply world scale polyethylene, polypropylene and aromatics plants along with our specialty oxo and fluid facilities.

Our proposed project adds a second steam cracker to the site, which provides feedstock for a second set of world scale polyethylene and polypropylene plants, an aromatics extraction unit, a second oxo alcohol facility, and a elastomers facility, the latter two being specialty products.

As mentioned earlier, we view specialty products growth as important and strategic in the overall performance of our portfolio. Like our base Singapore petrochemical complex, new facilities would be wholly owned by ExxonMobil. The technology we currently employ and plan to further enhance includes the capability to process a wide range of attractive feedstocks.

In 2005, we completed our feasibility study and defined the project scope. With the announcement of the project executive and project services contractor in December, detailed engineering is underway. But as we pursue these major growth projects, we continue our laser focus on the fundamentals of our business. Our self help program is critical in this regard.

Our focus on base business operating cost and revenue enhancement is consistent and relentless. We drive continuous improvements in numerous areas, a few of which are depicted on this chart. Energy efficiencies are continually identified through the extensive use of our global energy management system, described earlier in the Downstream discussion. Over the last three years, energy consumed per unit of output has been reduced by seven percent.

For steam cracking which makes up about 60 percent of Chemical’s energy consumption, and where we do have comparative industry data, our current rate of improvement is about 50 percent greater than the industry average.

Workforce costs are another major expense category where we have achieved significant efficiencies. As depicted in the upper right panel, over the last three years, we have reduced

our workforce by about 10 percent, which when coupled with volume growth equates to an overall productivity improvement of about 15 percent.

With respect to advantaged feedstock, we continue to expand our feedstock flexibility lowering raw material costs. Since 2002, we have increased utilization of advantaged steam cracking feeds by 20 percent. Over 55 percent of our current ethylene production is from advantaged feedstocks. We are targeting continued growth of some four to five percent per year. Technology development, increased synergies with refining and the Upstream and selective investment in feedstock flexibility are all key enablers.

Running our plants at capacity with fewer interruptions results in safer, lower cost operations. It also enables higher production volumes with little or no additional investment. The bottom right graph shows cumulative reliability gains since 2001 measured in millions of tons. These reliability gains alone are equivalent to the capacity of a world-scale steam cracker. Overall, self help programs added over $500 million to last year’s earnings as they have done over the previous few years.

Technology leadership has been key to delivering these results. In fact, as with the Downstream, maintaining our leadership in developing and rapidly deploying new technologies, underpins all of the various strategic Chemical business components I have described. This chart is the same format as the one used for the Downstream. Again, I don’t plan to cover the details. But once more, I believe it serves to illustrate that we have a very robust array of research programs directed at achieving strategic objectives in our three main focus areas, utilization of advantaged feedstocks, lower cost processes, and growth in premium products. You can see that our opportunity pipeline is full, and we would expect a sizeable number of these R&D programs to pay dividends further enhancing our competitive position.

Speaking of competitive position, let’s concludes by reviewing the comparison of our results with competition. With respect to capital employed, all of the competitors shown have maintained a relatively flat capital base over the past five years. However, aided by the pace and magnitude of our self help improvements, our financial results have grown faster than our traditional petrochemical competitors, with their earnings over this time period remaining essentially flat while ours have grown three-fold.

Dow who we consider a formidable chemical-only competitor, also increased earnings, but at a slower pace, and with a much higher capital base. Consequently, we are clearly leading the industry in return on capital employed. Over the past 10 years, we have averaged 14 percent return on capital employed compared to an estimated eight percent for industry, five percent for our petrochemical competitors, and 11 percent for Dow. These comparative return data demonstrate that our chemical business approach is delivering superior value for ExxonMobil shareholders. And with continued delivery of self help improvement and technical advancements in our base business, coupled with the major growth opportunities, we’re pursing, we are well positioned to extend our lead over competition as we move to the future.

That concludes my remarks, thank you for your attention. Let me turn it back to Henry who will outline the remaining program.

Henry Hubble

We’ll take a short break at this point. If everybody could be back and in their seats at 11 o’clock we’ll resume the program then when Rex will go through summary remarks, and we’ll take Q&As, thank you.

BREAK

Henry Hubble

Thank you very much. I’ll turn it back over to Rex for summary remarks, and then we’ll open it up for Q&A.

Rex Tillerson

Thanks again, Henry and welcome back everyone. As I mentioned in my opening remarks, the year 2030 energy demand will increase approximately 50 percent from today’s level, driven by economic progress and population growth. Technology will play a key role in tempering the growth of global demand through continued improvements in energy efficiency.

On the supply side, technology advances will be needed to economically find, develop, produce and transport new energy supplies. Increasing supplies to meet demand will require substantial investments. The international energy agency estimates that the investment required to meet global energy demand through the year 2030 will be $17 trillion of which six trillion is required in the oil and gas sector. We are in a long-term capital intensive industry, and investment decisions made today will endure for decades. Governments will also need to provide access to acreage, open markets, reduced barriers to trade, and avoid harmful policies such as subsidies and regulations that can weaken or distort the energy markets.

Finally, our industry is driven by long-term trends. Responding to those changes takes discipline and focus. Seeing past the market noise and understanding long-term market trends is one of the hallmarks of ExxonMobil’s approach. As an example, we recognized the evolving nature of the LNG market, and worked with Qatar Petroleum on how best to unlock the value of the North Field, the results of which are reflected in the breadth and diversity of our plans, the world’s largest LNG investment program, Gas-to-Liquids, massive pipeline projects, and world scale ethane cracking.

Similarly by understanding the key trends for long term success in refining we have established a superior portfolio of assets and are well positioned to serve the growing demand in Asia. While others were exiting the chemical business, we grew ours and capture strong returns throughout the cycle.

Many are concerned that the industry environment creates significant challenges and will reduce opportunities. In my view, these challenges play to ExxonMobil’s strengths. If you were going to put together an energy company to meet these challenges, how would you design it?

You would want a company that has scale, geographic diversity and a global organization that draws from its wealth of experiences, and delivers consistent superior results. You would want a company that has the technological and financial strength to pursue all opportunities, as well as the discipline to select the ones that are resilient. You would want a company that has a superior resource base, and the development and execution strength to complete projects, on or ahead of schedule, and at or below expected cost. You would want

a company that has a superior business approach that creates long lasting sustainable advantages such as molecular and physical integration.

In short, you would create an ExxonMobil.

That is why at ExxonMobil we are staying the course. Building on our advantages.

None of us know how long the current cycle will continue, but one thing is obvious; ExxonMobil is capturing more of the upside and increasing our advantage versus competition and growing long-term shareholder value.

That concludes my remarks, and I’m happy to open the floor for questions. I’m going to ask the other members of the management committee, to join me up front here on the podium.

And if you would, wait for the microphone so that not just the people in this room, but those are listening via the webcast and elsewhere can hear your question.

QUESTION AND ANSWER

Question 1

You said Capex guidance for the rest of decade rises from last year’s $18 billion per annum to $20 billion per annum. There was a hint, I think, in the presentation that some new projects are creeping in towards the end. Can you perhaps breakdown that $2 billion per annum increase into new projects, added into the mix and other sources of increased Capex?

Rex Tillerson

Well the substantial part of the change, that $2 billion increment is those large projects that I mentioned. Qatar gas-to-liquids which you’ve heard us advertise is something on the order of $7 billion. That is a 100 percent ExxonMobil project. The large investments in the chemical expansions that I described, the China project in Fujian, if you kind of do the sums on those projects, and if they all materialize as we anticipate and are hopeful that they will, then the largest portion of that increase is a reflection of capturing those projects. To the extent we either don’t capture them, or to the extent they slide further out in time, beyond the end of that period, then that spending level will be less than that.

So if you think in terms of kind of the ongoing base investment in the portfolio, this large portfolio that we’ve been talking about now for several years, that activity level is about where we have expected it would be for some time. And it’s been building since the merger, as we’ve matured a lot of the opportunities, moved them through the various stages of maturity that Stuart described to you, and Steve described. We’re now kind of at that run rate that we’ve been talking about for some time, which we said we thought would be somewhere notionally, in the 15, 16, you know, $17 billion run rate, depending on any given

year kind of how these things ebb and flow. So the increment above is really these new things that are large, and our commitments to them would be significant.

Question 2

In terms of production out in the 2010 timeframe, clearly the investment has been focused in gas. Can you break down production in 2010 in terms of oil versus gas?

Rex Tillerson

Let me make a general comment, and then I’ll ask Stuart to maybe comment further on that. I guess, I would disagree a bit with your characterization that the investment is more heavily weighted gas than oil. If you look at the investments that have been made in West Africa, the investments made in Sakhalin, the investments made in the Caspian, all are large significant oil projects. There is a heavy investment component in Qatar related to this growing LNG business that we’ve talked about for some time. So I think the balance is still there. And the balance within our resource base, which feeds all of these future opportunities is also still there relative to oil and gas future opportunities. Stuart, do you want to comment any further?

Stuart McGill

Just to add the split out in the 2010 timeframe is very close to 50/50 oil/gas. (Actual estimate is close to 60/40 oil/gas.) And in fact, if you would have been concerned about balance, these kinds of projects are directionally reestablishing balance between oil and gas.

Question 3

You have a number of major projects starting-up in 2006 and beyond. I don’t know if you could maybe build on this, and maybe compare the start-up level with the level that you’ve had over the last few years. And also, maybe comment on average reserve size of these start-ups, and things like time to peak production or margins.

Rex Tillerson

Yes, we’ve been at a fairly high level of activity of start-ups now for the last two years. And again, as you’ve seen the Capex ramping up post merger with the consolidation of the portfolio, the opportunity portfolio base, as we’ve matured that and moved it forward. As I said, we’re now achieving what I would say is kind of a run rate for us. So we have had multiple project start-ups for the last two years. And that’s not something new for us. It is very challenging. Stuart, why don’t you elaborate on that further?

Stuart McGill

The second part of the question had to do with the size of these types of projects. There’s not a material shift in a very general sense in the size. The very large projects, the Kizomba projects, for example, that started-up over the last two years were very large. As we look forward the Erha project is a large project. The LNG project is a large project. There’s not a material shift between the size of these projects versus what the last couple of years have had.

If you go further back, as Rex implied, there has been a build up going on, but we’re now at this run rate. And you’ll see a significant mix of large projects and smaller projects. The

large projects will, however, dominate the capital spend, and they will dominate the production rate that comes from those.

Question 4

I wonder if you could give us an insight into your forward strategy in Venezuela and in Russia. It looks like, from the major project start-ups that you don’t have anything going forward in Venezuela. And also in Russia, outside Sakhalin it seems that given the resource base in Russia, just wondering, after all of the effects over the last few years what your thoughts are there.

And just a second question as well, if we continue to have these sort of oil prices going forward, do you expect that your divestments in the upstream, the rate of divestments continues at that pace going forward.

Rex Tillerson

Well the business environment in Venezuela and Russia, I think, both of those countries continue to undergo change. Let me speak to Venezuela first. We do have opportunities in Venezuela to expand the Cerro Negro project. We see that as a viable expansion opportunity.

And we have another development there that we are in discussion with the Venezuelan government regarding a development plan. That whole environment in Venezuela is very fluid, as certainly, I think you can tell just by what you read and what’s reported. And until that settles down to something that’s stable, it’s very difficult to make any kind of decisions or any kind of commitments to major new investments in Venezuela.

I think at this point, we have continued the dialogue with them. We continue to provide input on what we think is needed and necessary, but are really keeping a lot of our attention on maintaining the soundness of the operations we have down there underway already which we’re very pleased with the performance of those. And it’s just kind of an ongoing process of dialogue and discussions with Venezuela about how you want us to participate or not participate. And that’s something that they’ll decide in terms of how they create the business climate. They’ll either create the conditions that allow major new investments, or they will not create those conditions. And the major new investments then, at least for us, are unlikely to take place. We will remain interested in the country. We see opportunities there, and it’s just a question of how they want to go forward.

In Russia, it’s a little of a similar situation although perhaps with a different tenor. Russia continues to go through change and evolution in how it wants to manage its natural resources, and more particularly its oil and natural gas resources. As to Sakhalin-1 we’re very happy with the performance there, we’re very satisfied with the level of support that we receive from the government and from the various agencies that we have to work with. It’s still a very difficult complex process, it requires a lot of attention and effort to work through their system of how they want to allow things to move forward, but we understand it pretty well. And I think we have all of the right relationships to make that a positive experience at the end of the journey. It sometimes is strenuous as you move along that timeline.

And so as to Sakhalin-1 we still are very confident about the future phases of development, as well as ultimately realizing some value for the gas, significant gas resources that are there. And we’re happy with the way we’ve been able to deal with the challenges of executing that project.

Beyond Sakhalin-1, the answer to the question that I gave last year on this has not changed very much. It’s still a question of the Russian government deciding where they want the foreign investors to play and how they want them to participate. And that seems to change as time goes on in terms of their view of that.

Because of our presence there in the country with Sakhalin-1 holdings, we have a significant presence on the ground both in Sakhalin and certainly in Moscow, just to work through all of the regulatory and government interfaces that are required to keep the project moving forward. We have excellent contacts, excellent relationships, and a excellent ability to communicate. And my view has been there’s only so much pushing you want to do on this whole process. And so we provide our views, we provide our input. But in some respects, I’m taking more of a patient view, of let’s see how this all kind of evolves. There will be some space in there somewhere for us to participate that will be attractive to us. There’s space today. You can force your way into it. I’m just not convinced that over the long term, that’s necessarily going to give us the kind of value that we would want.

So I think we just continue to watch how it develops. They know we’re interested. We’ve made that clear. We continue to talk to both the national oil companies and to others in the country about potential opportunities. And when the right thing comes along, if it looks right to us, then we’re in a good position to participate there.

The last part of your question was on divestments. Well that is an ongoing process. I guess the only thing the high price environment has done has caused others to place higher value on some of these assets than we would place on them. It’s not a question of assets that are purely unattractive to us, but it’s a question of what’s the right way to use your resources, a big piece of which are your human resources. And it takes a lot of human resource to operate any asset. And in some cases, we have assets that just don’t prove a meaningful material amount of value to us in the grand scheme of things. And if someone wants to give us full value, or perhaps even more value than we think is left in that asset, then we’re happy to sell that, take the people that have been having to manage that asset, and redeploy them to things of higher value. And so that’s really the question here. It’s not so much that the high price environment changes our view of it. I think it more changes the views of some other people of the value of the asset.

Question 5

Two questions, Rex. One in your presentation, you talked about 4.6 billion barrels of new resources that added in 2005. Can you give us a rough estimate of how much of that is coming from your exploration program is of commercial development. And of the new reserves from your exploration program, do you have a split between oil and gas or by region?

The second question is on the LNG market. I think historically companies do not want to proceed with the development or final investment decision until they have, probably 80, 90 percent, of the gas sales committed. With U.S. and Europe as both have become a major net importer in the coming years, does that change your view? I mean how much of the gas needs to be committed, before you would go ahead? Because by doing so, you may significantly shorten the cycle time, and correspondingly increase your net present value. Thank you.

Rex Tillerson

Let me answer the second question, first, and ask Stuart to add anything he would like, and then answer your first question.

Gas today still is very much driven by regional market factors. It’s not yet a purely global commodity, although as the LNG business grows it will become more of a global commodity. It doesn’t behave exactly that way today.

What is different, though, is when you look at the United States markets, and you look at the European markets, and the continuing development of the European markets, particularly in the U.K. and in continental Europe, those have become and are becoming what we call liquid markets.

The U.S. is – and North America is a fully liquid market. If you look around the markets in the U.S. today you would be hard pressed to find very many long-term gas contracts in place today. That’s where Europe is headed as well with their decontrol and their deregulation and wanting to increase competition in the marketplace. The European union has focused on long-term contracts as being something that they do not particularly find to be contributing to a competitive marketplace.

So in those two major consuming markets, where you can look at the future domestic supplies availability, it’s clear imports are going to be required, and they’re going to be necessary. The gas is going to come to those markets. It’s going to come into a liquid market. It’s not going to come into a market that wants to contract long term. We’re selling an enormous amount of gas in Europe and the U.S. today into that liquid market which gets sold on a daily basis, a weekly basis, and maybe a long term contract as a monthly basis but that’s the nature of how the markets evolved.

So we’re very confident in terms of our understanding of those markets, and therefore, we’re very confident in making the kind of investment commitments in the LNG projects that are targeted to those markets. And that has moved these large trains forward in time. That’s what’s really behind this rapid growth you see in Qatar and the ultra large trains, I’ll call them, the 7.8 million ton trains, the development of the ultra large LNG transportation ships, larger than the industry norm. And our investment in the receiving terminals, all of that is based on our understanding of how liquid markets today behave and our expectation that it is not going to change in the future. If anything there’s more pressure particularly in Europe, to allow those markets to continue to open up. And we’re confident with that.

And we’re confident enough to make those major investments in Qatar because we see the demand is going to be there for that gas.

In Qatar and in some of the other trains, and in certain segments there are still long term contracts. And in other markets around the world that is the norm and so you tailor your efforts to serve those markets, but what’s driving those big trains in Qatar are the liquid markets in Europe and the U.S. Stuart.

Stuart McGill

I have nothing to add in the second piece, but coming back to the first part of the question, last year was, as I shared on my chart, an exceptional year for resource ads. The largest single piece in that resource add, of course, is the piece that came from Qatar with the large LNG trains. If you take that piece out which is roughly 2.2, the performance of the rest of the business was very typical with long-term performance and looking out over a long period of time, where the overwhelming majority of the ads come from by the bit drilling, something in the order of 75 to 80 percent over the long period.

Rex Tillerson

So I would just add one thing on the LNG comment, too, that if you look at the financing that we’ve been able to arrange for those large LNG trains with Qatar petroleum the financiers sees those liquid markets the same way we do.

Question 6

If I could just return to Venezuela you were notable by being alone in refusing to accept term changes this past year, and ultimately sold out to the position. If we were to see a change to the heavy oil terms, would you assume that you would stick by your principles, and ultimately would exit rather than accept a change in terms? Thanks.

Rex Tillerson

I assume you’re saying a deterioration to the terms. You could have a change as positive, I suppose, to the environment. But if you’re talking about further erosion to our rights, I think, you know, we’re going to continue to assert our rights that we believe are provided for in the original agreements that were entered into in compliance with law. And where we have a difference of opinion there, we’re going to reserve our rights, which is what we’ve done with regard to the royalty increase.

In terms of exiting something in a weak environment it is often times difficult to do. In the case of our exiting of the joint venture operating services contract towards the end of the year we were very satisfied with the value we got for our proportion of that joint venture, which we sold to our partner who wanted to continue, which is fine. They had a different view of that than we did, so we were able to get what we feel was very good value for that holding, and let them carry on. And we’re not an obstructionist to whatever they and the Venezuelan governments want to do with that contract. I’ve got value for my shareholder, I’m out of here. So it comes down to getting the value though, we’re not going to buy ourselves something or just jump out just because the heat gets a little hotter in the kitchen. We’re certainly willing to deal with that.

And deal with in a constructive positive manner. We’re not trying to make a point to anyone here. We’re not trying to be an obstructionist. We’re trying to contribute to the whole discussion of what they’re trying to do and what’s really, really necessary for the long term viability of Venezuela’s oil industry.

Question 7

If I could ask a different question, your dividend yield is now at a record low, what’s holding you back from simply making a step change upwards in the dividend in the way that your profitability has taken a step change up? Thanks.

Rex Tillerson

Well, obviously we have a lot of flexibility to do a lot of different things around the dividend. I think my view is, as I indicated in my earlier remarks, there’s a certain expectation, I think, of our performance in that area in the future. We want to ensure we meet the expectation. And I think we want to ensure that we are keeping the healthy cash flow position that we have, positioned to give the shareholder the best value over the long-term. And that’s the balance that we’re always trying to maintain, recognizing that we’re in a part of the business cycle. We’re at one extreme of the business cycle, and that will change, it always does. And when you go through a change in the business cycle, you never know what kinds of opportunities may present themselves. And I’m mindful of that. And I want to ensure that we are well positioned with the flexibility to take advantage of and seize any kind of an opportunity that might present itself as these cycle changes occur, because that’s when the opportunities start appearing.

I think it’s just a question of wanting to continue to reward the shareholder, with well above inflation rates increases in the dividend which we’ve certainly done, shared a little bit more of that this year, reflecting the strength of the business. But we do have enormous cash requirements to keep the business of the size and scale of ExxonMobil’s going, as I mentioned. We’re at a 45 billion annual run rate on using cash, a big portion of which is going back to the shareholder through the dividends and share repurchases.

Question 8

You mentioned adding about two million BOE per day by 2015 to your production profile, which if you do the math, roughly three-and-a-half percent growth rate, a little bit better than your recent target of three percent unofficial or official. You know, as you go more global yet, you encounter more production sharing agreements, which are, of course, a drag on that profile. Can you comment on how much of a drag you see in the years ahead? And of course, this is a trend that’s pretty much not going to reverse, maybe with the exception of Canada and a couple of other OECD countries. The trend for PSC’s to have an increasing drag on your production profile, and something that all of the majors face. Thank you.

Rex Tillerson

First let me clarify what the chart, I’m pretty sure you’re referring to, which is the production adds from the new project start-ups, it was in Stuart’s presentation that fills to the two-and-a-half million barrels a day. That is the production adds from new projects. Now you have to put that on top of the base, and of course, the base declines as it does. And as in fact, as

Stuart showed on that chart, the point being made there was the mix of our production, the nature of the production which traditionally, we’ve had a higher proportion of projects that have this shorter plateau and you experience more of a decline that’s typical of the base.

Many of the new projects that are coming on stream across this timeframe have a different character to them, because of the size of the resources that are in place, and the optimum investments that we see as being prudent to make to produce those, lead to a build up, to a very long plateau which means we’re not going to see decline, as a result of those projects for some time.

So I don’t want leave you with an impression that that chart was saying the total volumes are going to be up by two-and-a-half million barrels a day, because you’ve got to lay that on top of base decline. I think the chart that Stuart showed towards the end of the decade, shows us approaching an increase of about a million barrels a day, to five million barrels a day.

Now in terms of the question about PSC’s, if you look at the mix of those volume increases, the charts you were just asking about, you know, a big piece of that increase is in Qatar with the LNG projects. Those are not PSC’s. We don’t have PSC fiscal terms around the big LNG investments, and those production volumes are really a function of our ability to maintain reliability and performance.

In the total mix of volumes going forward, I guess that I don’t know that I’ve actually sat down and looked at that question, and I’ll ask Stuart to comment further, again, as well. But if you look at the past, the past being the past five years, all the way up to where we are today, we have had this same question come up before, and we have tried to address that with the chart that Stuart showed in terms of our ability to capture the full value of our upside in the price environment. And you saw the correlation which is almost one-to-one, the correlation, I think is 0.9-something.

It says that in the mix of our portfolio, we have a good mix of PSC, as well as non PSC type fiscal regimes, that allows us on average to continue to capture most of that upside. This is the nature of all of the big opportunities that we’re pursuing, each of them different types of fiscal structures. And I wouldn’t, necessarily agree with your conclusion, that in the future, that’s going to be the pattern or the norm. Clearly, anything that we’re trying to negotiate in today’s environment because of the high prices puts a lot of pressure on the structure of those, and we’re mindful of that which is why we take our time. We are patient and we just have to keep to what we know is necessary for the long term performance of those. Stuart.

Stuart McGill

There are a couple of points to add. You know, the connection that PSC’s are bad, and other things are good, is not something that I would subscribe to. PSC’s can be every bit as good. And ultimately, it’s value to the shareholder that matters in this game. The volume effects may be more prevalent in PSC structures, than JV structures, but the value to the shareholder doesn’t have to be different.

The other observation I’d make is that in addition to the joint venture projects in Qatar which play a significant role as we look forward, you correctly pointed out that activities in Canada, and I would also add activities in Alaska, and activities in North America, and

activities off shore West Australia and I could go on, are also not PSC regimes. And so I do not expect a major shift in the balance in our portfolio between different types of contract structures. If you just put them into two broad buckets of PSC’s and non PSC’s, something in the fifth to a quarter of the total production will be the range that they will fall into in the recent past, and in the foreseeable future.

Question 9

Rex, I had two somewhat unrelated questions, one of which is a bit of a follow up on a prior question, I’m wondering to what a extent a variable special dividend is something that’s been considered as an alternate to or supplement to your returns to shareholders which might take into consideration the volatility of the business environment, and therefore to some extent the volatility of the cash generation that goes along with it.

The second question is a little bit more big picture. It almost sounds as if getting right down to the subsidiary business unit level, that change in approach no matter how subtle, or even in strategy is almost heretical. And thus, I’m kind of wondering exactly what it is in terms of business conditions, environment, or what have you, that might lead to consideration to even a subtle change in approach to strategy at the business unit level.

Rex Tillerson

Well as to the first question, around considering other alternative means of dividend or really returning value to the shareholder, we do look at all of the options, every year we look at all of the options as part of our financial plan. And when I look at what a special dividend has done for other companies or corporations that have made such a special dividend, it’s not evident to me that it has done anything for long term shareholder value. It may scratch the immediate gratification itch of some. But for our shareholders, which typically are in it for the long haul that’s not delivering best value to them. And I think, again, I mentioned the context you have to look at our objectives, and our results over decade type periods, because that’s the length of time in which these things take to play out and that’s the case in terms of our financial planning and the management of cash flow as well.

So to answer your questions, yes, we look at it. We consider all of the other alternatives in terms of is there another way to return more value to the shareholder in the complete and total context of shareholder value and our objective to grow shareholder value over the long term. But at this point, my conclusion is that none of those types of programs really provide anything of long-term value to the shareholder.

As to the second question, I guess the only way I can respond to that is say, you know, the ExxonMobil culture is something that a lot of people would like to understand better. I’m not really going to help them understand it, because it’s the source of our competitive advantage. But if what’s underlying your question is, does our culture, in any way, inhibit or put a blanket on innovation, entrepreneurial ship, new ideas, I can tell you it absolutely doesn’t. We couldn’t produce these kinds of differentiating results if that were the case. We get the best out of our people, 24 hours a day, seven days a week, 365 days a year. We have the best people in the industry, the brightest people in the industry. They understand expectations and they understand our expectations are always improving. And you can’t improve if you’re not looking at where you are today relative to the environment around you, and where you think it’s going, and saying now how am I going to not just maintain my

competitive advantage in the future, how am I going to widen that out further? And that’s what we’ve done. All of the indicators show that we have increased the gap between ourselves and the competition. And that doesn’t happen just because we set some strategies up here at the top. That happens because of what’s happening with 85,000 people around the globe every day of the year.

Question 10

Got some quick Upstream questions. With fast drill what percentage of Exxon operated wells are currently using it? And what kind of expansion plans do you have?

Stuart McGill

What percentage of wells are using fast drill today? The overwhelming majority.

Question 11

The next question, will you drill a second deep shelf well before Black Beard TD’s?

Stuart McGill

Would we drill – say it again?

Question 11

Will you spud another ultra deep shelf well in the Gulf of Mexico before Black Beard TD’s, which is total depth?

Stuart McGill

Have you got a rig that’s not being used?

Question 12

OK. That’s fair. The last one for me, in terms of your extended plateau projects, what are the maintenance capital needs for them versus say, conventional projects, or what’s the maintenance capital need as a percentage of the total project commitments? Because it seems like they’ll kick out a lot of free cash.

Stuart McGill

Yes, but the nature of our business is always high front end costs, it’s either made up of a relatively select number of large projects, or a large number of small projects, but they’re all high end front costs. This phenomena of how much capital have you got invested that is not yet producing. There is a phenomena with the change in the mix of projects, where you can have a larger amount of capital that’s not yet online, but that’s not a major factor as we look at our mix of projects. It only happens if you have a large change in mix. And this change in mix has taken place over several years. And as we go forward, we see much more of a running rate in that project mix not a large shift in the nature of the projects. So that’s not going to be a fact of any importance.

Question 13

You made the comment that Exxon is not likely to buy expensive volumes, which I think, probably surprises no one. There’s no question you’ve got a substantial resource base. Even in your own energy outlook, though, post 2010, you do show a growing dependency for industry on Middle East volumes. I am curious that if Exxon would, for whatever reason,

not gain access to projects and whether it’s Saudi, Iraq, Iran, some of these key resource holders, might that change your view on what currently appear to be expensive acquisitions? Or is the presumption that at some point over the next 10 or 20 years, you will, inevitably gain access to those types of countries, and therefore, the long term future of Exxon is secure?

Rex Tillerson

Well I think my own expectation is that with time we will gain access to additional resource opportunities in the Middle East. And that’s a reflection of our past record. We already are a participant, set Qatar aside, in terms of oil we’re a participant in Abu Dhabi. Stuart referenced our selection this past year based on our technology that’s been demonstrated, and our capability to execute things well to take a participation in the Upper Zakum oil field, this is the fourth largest oil field in the world.

So I think we have a certain reputation that we’ve established in that part of the world that’s important. It has been based on what we’ve demonstrated we can do as opposed to talking about what we can do. And I think we’re getting some recognition for that now, and as time goes by. And the other larger resource holders in the Middle East, Kuwait still is discussing actively their interest in proceeding with the project Kuwait of which we have a consortium formed and ready to participate. As the situation in Iraq evolves over the years ahead, and even as the situation in the Kingdom of Saudi Arabia evolves in the years ahead, I think our approach is to be active in the region. Be sure that we execute the things that we’re involved in well so that our capabilities are clearly demonstrated and recognized. We don’t have to sell it as much as they can look at it and say yes, these folks do things differently and they deliver on what they commit.

Then as time goes by and each of those countries evaluates its own needs to continue its own development of its resources, then I think we will be well positioned relative to any of the competition to have additional opportunities to participate in the future.

Whether that happens or that doesn’t happen, and when that happens, it’s just all part of taking this much longer term view of our approach which is we are going to be active in and exposed to new emerging opportunities around the globe. Diversity is still a very important element of our strategy. It’s an important element of our performance to be exposed diverse geographically, diverse from the types of resources which allows us to apply the wide range of technologies that we can bring to bear on that, that’s not going to change.

Question 14

If I could try two unrelated questions, Rex, please. The first one is on LNG. You have quite a disproportionate amount of LNG investment coming up over the next several years. How do you see your incremental return on capital employed moving, as those projects come to fruition?

And the second question is, again, back to the issue of cash flow access, the resource and so on. In the list of Canada, what is the logic of current relationship with Imperial Oil, why would you not want to own 100 percent of that business?

Rex Tillerson

Well in terms of our future return on capital employed, and how the mix of new investments going forward are going to effect that, on an absolutely basis, you know, I can’t tell you what that’s going to be, because I don’t know what the prices are going to be in the future. On a relative basis to our competition, though, our expectation is we will continue to lead the competition on return on capital employed throughout the business cycle, the highs and the lows. And that advantage we’ve built, will not only be maintained, but we hope we’ve challenged ourselves, to continue to grow that advantage in terms of the return.

The discipline that we take to making those investments on the front end takes all of that into consideration. It considers the fact that the business cycles move up and down over the life of these projects, most of which are 25, 35, 40 year type projects. And so the resilience of those, and the robustness in terms of their performance across that cycle is part of that whole investment decision making process. So on a relative term to competition, my expectation is we will continue to lead the competition on return on capital employed throughout the cycle.

The second part of your question, Imperial Oil. Well we’re happy with our holdings in Imperial Oil at the level they’re at today. Imperial is performing quite well. And for the time being we’re just going to maintain our status quo there.

Question 15

Estimate of Exxon and others is that world energy demands will increase by roughly 50 percent by 2030. Would you agree that there would be need for a considerable growth in coal and nuclear to achieve that?

And secondly, could Exxon participate in these other energy sectors at some point? And how would they do it?

Rex Tillerson

Well if you look at our energy outlook, out there in the year 2030, it indicates that oil, natural gas and coal will continue to retain roughly the same respective share of total energy supply that it does today, oil and natural gas around 60 percent, coal around 22 to 24 percent. So we would anticipate that coal will grow proportionally with that demand growth as well.

In terms of our interest in pursuing energy supplies other than oil and natural gas, I think, for today we see a rich portfolio of opportunities in oil and natural gas sector, which are going to continue to be very much in demand through that period, as I said 60 percent in the year 2030 about the same as today. It doesn’t mean that we won’t keep our eyes open for areas that we can add value. But to just move into another commodity business for the sake of owning that commodity is not particularly interesting to me. And so, I think it’s really a question of in our own technology, exploration of technology and development of new technologies, if something were to emerge out of our research efforts, that we thought we could add value and lift the value of an alternate commodity, then obviously, we’d take a hard look at it. But to me, that is kind of the underlying principle, what can I do to really create more value in that alternate than anyone else can create? Otherwise, I just get it in for

the sake of expanding into a new business. And I don’t think that’s necessarily in the best interest long-term for the shareholder.

Question 16

I have a couple of other questions about the two million barrels a day equivalent net capacity adds from major projects, and I apologize if you addressed these in your comments already, but one question I had was what’s your average working interest in those projects?

And secondly, on the underlying decline rate that you referenced it looks like with the numbers that you’ve given us, it infers only about a one to one-and-a-half percent decline rate, which is much lower than kind of conventional wisdom on a global decline. Is there some other growth wedge from all other projects, that aren’t major projects that’s not included in here? And if so, what would that be?

Rex Tillerson

Stuart, since your chart is generating all of this interest, I’m going to let you answer that.

Stuart McGill

I’d say on the decline side, we see base decline, which also includes what program uplift at about the same level that we’ve seen in the past, the base is performing consistent with our expectation. And so it is typically in the range of four to six percent. We see a decline rate, as we’ve mentioned before something closer to the six than four in the base.

And so what is very important in that base decline, though, is the work program drilling that I referred to in my remarks, which provides a substantial offset to underlying decline in those assets. Now the first part of the question was average working interest in those major projects. If you think about a third, on average about a third.

Question 17

I guess as a follow up to Luis’s question are you doing significantly more to mitigate declines to keep that decline rate steady? Is that becoming a more important effort?

And secondly, Rex, you mentioned that opportunities come with changes in the business cycle. If there were abundant acquisition opportunities, what kind of asset would you want more of?

Rex Tillerson

Well as to the first question on whether we’re doing anything different in terms of managing decline rates, the answer is no. As stewards of the resource, that’s our first obligation. You know, we don’t own any these wells, we own a few resources due to feed property holdings, but by and large, we’re stewards of the resources that are owned by our host governments, or by lease owners, royalty owners. So we are going to manage those resources prudently to capture the maximum amount of the resource no matter what, obviously it has to be economic. But just because the price gets higher one day and lower the next, doesn’t alter the way we manage the depletion of those resources, but has little effect.

In terms of the things that we’d be interested in the future, for us it’s got to be large, or we can just exert a lot of energy and effort of assimilating something that’s not going to have

much of a material effect on our overall results. So it’s going to be large. It’s going to be significant. It’s going to be in-line with our core business holdings today. And it will all depend on the quality of what we see, in terms of the assets, and the resources and the future opportunities that we might see and how we might see that integrating with our current holdings. But it’s going to have to be large, and it’s going to be significant.

Question 18

I was just wondering with your Capex budget, sort of flattening out through 2010, if you could discuss what your cost inflation assumption is in there.

Rex Tillerson

Well that is a variable across a lot of those projects, because they all had different characteristics. The project management execution responsibilities of the development company and in the Upstream of our project management groups are to manage that in terms of mitigating the effects of higher cost of materials, services, that would tend to drive the cost of these projects up. Things like the Fast Drill process offset those higher costs. The cost of rigs, obviously, are up tremendously. The cost of all oil field services are up tremendously, so what’s our response to that. That’s the comment I made earlier, that we don’t except that we can’t influence that. We influence it, of course, in our contracting strategies, to try to manage that. But we also influence it in our operating capabilities. So Fast Drill is a way to offset those higher drilling costs.

A lot of other technology and operating advances are what allow us to offset those growing costs. There is not an inherent factor in that Capex outlook, because our Capex outlook is really an accumulation of what the organization is presenting to us in terms of investment opportunities. And we look at that total portfolio where we make some decisions on those we think are most likely and those that probably need some more work, in order to bring them up to the level of confidence they we require to invest. And so it’s really kind of a sum of the opportunities that are in the portfolios as opposed to us picking a number and saying there’s the capital spending we want to undertake in the next year or two. It’s built from the bottom up. And so each of those projects as a result has varying cost inflation elements to it depending on how they’ve been able to manage those. There is not a factor I could give you that says there’s three percent across the board. We don’t take that simplistic of an approach to it.

Question 19

Two part question on the inherent challenge of access to resource. First, given your arguably superior technology in the industry, are there any areas that you’re revaluating as far as, you know, an area that might be considered a mature basin, where you’re taking a fresh look at and defined conventional thinking in a particular play.

And secondly, with the changing role of NOC’s in the sense that many of them are looking more like international oil companies in competing with you in international markets, and not just in their own borders, how is that reshaping the way you think about potential projects, and whether or not you consider that a serious threat.

Rex Tillerson

Well in terms of new approaches or areas that we’re evaluating, that is always an ongoing activity, for both our exploration company as well as our production company as they’re dealing with the depletion of resources. We always are looking for where the new technology may allow us to undertake new areas of activity either deeper under existing, producing horizons, or further out into environments that previously we could not access due to technology limitations.

So there is not any particular – in terms of saying well we’re focused on this particular area, we’re focused on all of the resource basins around the world, the plays around the world. In fact, the chart that Stuart showed you of where our new exploration plays are located early on in his presentation, those are all the result of new play concepts that emerge from the exploration companies’ activities around putting together a whole earth model, we call it in terms of where are the new play concepts that have potential? So it’s an ongoing process out of those activities.

In terms of the impact and the role of national oil companies, obviously in certain opportunities where they are more aggressive, than perhaps we want to be, we’re not going to prevail in terms of capture of those. By and large, there’s been little impact, thus far on our pursuit activities, quite frankly and I think it’s for a couple of reasons.

One, there are some opportunities that they simply are unable to pursue because they don’t have the technical capability or the operational execution capability to undertake those. So there are some parts of the global space that they will find it very difficult to compete. And I think they recognize that. I don’t think I’m saying anything that they don’t know themselves.

And in other areas, they are willing to pursue some opportunities that we would view as being highly marginal against our standards of economic performance. I guess, the different standard of economic performance, they view them attractive against what they’re trying to capture over the long term. So there, we don’t really find ourselves in direct competition either because that opportunity, as we would see it today would probably not meet our criteria in terms of our wanting to capture it.

I think, you know, we’ve been through times like this before, in the past, where there has been emergence of various countries, putting a lot of emphasis on their own energy supply, security. And we’ve worked through that in years past. We’ll work through this one as well. And out of all of that, as I said in these business cycles, out of some of that activity may emerge some of these opportunities I was talking about, as things either don’t work out the way people thought they would. Or they encounter some complexities where they feel we can be of assistance. It may open some doors for us to come in and participate later. So I never feel like the result today necessarily means the game is over because a lot of these things tend to go through an evolution and then come back around again. And as I said, we’re going to maintain our credibility and be able to demonstrate to people this is where we can bring value. We can add value to your opportunities in these ways. If you see a role for us, we’re always happy to talk.

Question 20

A couple of questions relating to Qatar given your substantial investment plans in that country, and in particular relating to the North Field itself, looking over the last couple of years, it seems as though roughly 90 percent of your proved reserve additions have come from that field alone. So the question is what’s left to book? Presumably GTL is one that’s still in the sidelines, given the Qatari’s have yet to fully sanction that project, what else might be there?

The second question relates really more to the North Field in its entirety, given your substantial share of operations in the field, it seems as though you would have accumulated a more complete data set than perhaps your peers drilling wise. What does that tell you about the overall resource potential in the North Field? I’m thinking here in the context of the minister making quite clear his moratorium on new projects, beyond the 25 Bcf a day, which gives him the 100 year reserve life he’s looking for out of 900 Tcf. Is 900 Tcf too high or too low in your view? And what supporting evidence do you have total wells drilled, average success rate, view or lack thereof about the homogeneity of the reservoir, and how that’s evolved? Thank you.

Rex Tillerson

Let me start with the back and go forward. In terms of the resource itself in the North Field, the pause is how I would characterize it, that the state of Qatar and the minister have elected to take at this time in terms of allocating additional block concessions to future projects, I think, was the appropriate thing to do, and was the right thing to do given the level of activity they have under taken, and the commitments they already have made. And the fact that we’re only now beginning to get some production history on that field with the developments that have been undertaken. There have been a lot of wells drilled, appraisal wells to better understand that field. It is a giant field. There’s nothing that I would certainly want to suggest that it’s anything other than what the minister has represented it to be.

But I think it is helpful to have an opportunity to take a little time and let the technologists, the geoscientists and the reservoir engineers update some of their models. Have a little better view of how this field may behave in the future. It’s huge, but it’s not homogenous. The field has a lot of character across it in terms of its gas composition and a lot of elements that are important to understand. So I think the minister has done exactly the right thing to say look, we’ve put a lot out there. There’s a lot going on. People have got plenty to work on. Let’s take a breather for a couple of years, and let’s study where we are. And then, we will have a more thoughtful plan about – for Qatar as to what do we want to do from this point forward, to manage that resource in the best interest of the country which is really their objective, and that’s what we’re there to help them do as well.

In terms of our holdings, you know, we are the largest participant Qatar has across the slate of allocation of resources from the North Field. We’re very proud of that. We think it’s a reflection of the approach we took with the state of Qatar early on to say, look this is an enormous resource. We’re not interested in coming in here and negotiating one deal with you. We could do that, and that’s what everybody else has kind of done. But we said, you know, what we want to do is come in and talk to you about what’s the right way to manage

this field for the next 100 years. And you need a plan to do that, let us help you with that, and that’s what we did. So we set about a plan, and that’s what you see being executed by the country today.

So we’ve had a great relationship there. It’s a very positive relationship. One of a high degree of mutual respect, for their visions of where they want to go, how they want to manage that for the benefit of their people. And I think they have a lot of respect for the value that we’ve been able to bring to all of that. So we’re very satisfied with where we find ourselves today.

And when this study is completed after a couple of years pause, you know, I think we’ll be talking to them about what else might make sense for them to do with us. And they’re going to do some things with others as well, and that makes sense for their country too.

I think that’s all the time we have with the commitments we’ve got following this. I do thank you all for your attendance. I appreciate your thoughtful questions and the interest you take in ExxonMobil. Thanks.

END

Slides presented at an analysts' meeting held on March 8, 2006

Analyst Meeting

New York

March 8, 2006

Analyst Meeting

New York

March 8, 2006

Exhibit 99.2

Cautionary Statement

Forward-Looking Statements.

Outlooks, projections, estimates, targets, and business plans in this

presentation or the subsequent discussion period are forward-looking statements. Actual future results,

including demand growth and mix; ExxonMobil’s own production growth and mix; the amount and mix of

capital expenditures; resource additions and recoveries; finding

and development costs; project plans, timing,

costs, and capacities; revenue enhancements and cost efficiencies; industry margins; margin enhancements

and integration benefits; and the impact of technology could differ materially due to a number of factors.

These include changes in long-term oil or gas prices or other market conditions affecting the oil, gas, and

petrochemical industries; reservoir performance; timely completion of development projects; war and other

political or security disturbances; changes in law or government

regulation; the outcome of commercial

negotiations; the actions of competitors; unexpected technological developments; the occurrence and

duration of economic recessions; unforeseen technical difficulties; and other factors discussed here and

under the heading "Factors Affecting Future Results" in the Investor Information section of our website at

www.exxonmobil.com.

See also Item 1A of ExxonMobil’s 2005 Form 10-K. Forward-looking statements are

based on management’s knowledge and reasonable expectations on the date hereof, and we assume no duty

to update these statements as of any future date.

Frequently Used Terms.

References to resources, resource base, recoverable resources,

and similar terms

include quantities of oil and gas that are not yet classified as

proved reserves but that we believe will likely be

moved into the proved reserves category and produced in the future. The discussion of reserves in this

presentation generally excludes the effects of year-end price/cost revisions and includes reserves attributable

to equity companies and our Syncrude operations. For definitions of, and information regarding, reserves,

return on average capital employed, normalized earnings, cash flow from operations and asset sales, and

other terms used in this presentation, including information required by SEC Regulation G, see the

"Frequently Used Terms" posted on the Investor Information section of our website. The Financial and

Operating Review on our website also shows ExxonMobil's net interest in specific projects.

•

Industry-leading safety performance

•

Record financial performance

–

Net Income

$36.1 B

–

ROCE

31 %

–

Cash flow from Operations

and Asset Sales

$54.2 B

•

Cash Returned to

Shareholders

$23.2 B

•

Capex

$17.7 B

2005 –

Record Results

Normalized Earnings

•

Superior results in all business

lines

•

Industry-leading results across

the cycle

•

Capitalizing on competitive

advantages

Chemical

Downstream

Upstream

Net Income

2005 –

Record Results

'01

'02

'03

'04

'05

Disciplined

Investment

Operational

Excellence

Industry

Leading

Returns

Superior

Cash Flow

Growth in

Shareholder

Value

Proven Long-Term Approach

Investing for the Future

Capex by Business Line

Chemical / Other

Downstream

Upstream

Disciplined Investment

North

America

Geographic Capex Distribution

$B, avg. 2001-2005

Europe

Africa

Asia Pacific/

Middle East

Russia/Caspian

Other

'01

'02

'03

'04

'05

Investing for the Future

Chemical / Other

Downstream

Upstream

Planning Range (Total)

Disciplined Investment

Estimate

Capex by Business Line

'01

'02

'03

'04

'05

'06

'07-'10 Average

Technology Leadership

Disciplined Investment

* Based on public information

•

Consistent, long-term approach

to technology investment

•

Focus on proprietary research

leads to competitive advantage

•

Balance between breakthrough and

extension of existing advantages

•

Technology process managed to

maximize value

Technology

Spend*

Avg.

2000-2004

Total

Patents

2001-2005

100

200

300

400

500

600

700

XOM

RDS

CVX

500

1,000

1,500

2,000

2,500

XOM

RDS

CVX

•

Rigorous management process

•

Maximize shareholder value

•

Cash flow total of $13.6 billion

over the past five years

•

Cumulative earnings impact

of $4.6 billion since 2001

Chemical

Downstream

Upstream

Coal & Minerals

Asset Divestments, 2001-2005

Effective Asset Management

Disciplined Investment

'01

'02

'03

'04

'05

Employee

Contractor

Lost Time Incident Rate

Incidents per 200k hours

U. S. Petroleum

Industry Benchmark*

Safety Leadership

Operational Excellence

* 2005 Industry data not available

0.0

0.1

0.2

0.3

0.4

0.5

'01

'02

'03

'04

'05

•

Common standards and culture

•

Integrated, global processes and

systems

•

Flawless execution

•

One team, multiple resources

•

Continuous improvement, rapid

deployment of technology and

best practices

Global Functional Organization

Operational Excellence

Support Services Example

Operational Excellence

1998

2005

Inflation

Efficiencies

Growth/

Other

Support Services Costs

$B, FX adjusted

5.1

0.6

0.2

(1.5)

4.4

Consolidate into

Low Cost Locations

Standardized / Optimized

Common Business Systems Backbone

Implemented at Merger

Global Organization

Common / Global

Processes

Standard / Global

IT Systems

Cash Operating Costs

•

More than $1 billion in cost

efficiencies in 2005

•

Another $1 billion expected

in 2006

•

More than offsetting inflation

•

Significant productivity

improvements

Inflation

Cost Control and Productivity

Operational Excellence

Workforce

Cash Operating Costs at ‘05 Forex & Energy price*

* Operating costs (see Frequently Used Terms)

excluding depreciation and depletion

Thousands

105

'01

'02

'03

'04

'05

'01

'02

'03

'04

'05

Delivering Superior ROCE

Industry-Leading Returns

** Calculated from public information on a before-tax basis

and converted to after-tax using average corporate tax rate

RDS

CVX

XOM

Return on Capital Employed*

5-Year Rolling Average

Competitor data estimated using a consistent basis with

ExxonMobil, and based on public information

'01

'02

'03

'04

'05

-8

-6

-4

-2

XOM

RDS

CVX

2001-2005 Cumulative Asset Write-offs**

Cash Flow from Operating Activities*

Superior Cash Flow

•

Record cash from operations

Over $48 billion in 2005

Average $32 billion per

year from 2001 to 2005

•

Capturing the upside

Excludes asset sales

CVX 2005 cash from operations estimated based on reported earnings and DD&A

XOM

RDS

CVX**

'01

'02

'03

'04

'05

Capturing More Upside

XOM

RDS

CVX**

Indexed Cash Flow from Operating Activities*

% of 2001 cash from operations

Superior Cash Flow

•

Capturing more of the upside

than competition

•

Strong performance across

all business lines

•

Long-term approach

appropriate in cyclical

business

Excludes asset sales

CVX 2005 cash from operations estimated based on reported earnings and DD&A

100

125

150

175

200

225

'01

'02

'03

'04

'05

'00

'01

'02

'03

'04

'05

Superior Distributions

Dividends

Share Purchases*

* In excess of dilution

•

Distributed $79 billion since

2000

•

Paid dividends for more than

100 years

•

Increased annual dividend

payment each of the last

23 years

•

Annual dividend increased 9%

per year over last 3 years

Cash Returned to Shareholders

Growth in Shareholder Value

100

102

'00

'01

'02

'03

'04

'05

Share Buyback Program

XOM

RDS

CVX**

Growth in Shareholder Value

Shares Reduced via Buybacks*

% 2000 shares outstanding

Buyback Contribution to EPS

$/share

Period end shares outstanding based upon publicly available data

CVX not shown past 2004 because of Unocal acquisition

0.00

0.10

0.20

0.30

0.40

0.50

0.60

'00

'01

'02

'03

'04

'05

•

Shares outstanding reduced

by 12%

•

Market cap increased by 26%

•

Share price increased by 43%

Growth Since Share Buyback Inception

Indexed Growth

Increasing Value per Share

Growth in Shareholder Value

Market cap growth

Value of buyback program

Stock price growth

Shares outstanding

100

110

120

130

140

150

'00

'01

'02

'03

'04

'05

Corporate Summary

•

2005 record year

•

Long-term approach delivering

superior results

•

Building on our advantages

•

Delivering rapid sustainable

business improvements

Disciplined

Investment

Operational

Excellence

Industry

Leading

Returns

Superior

Cash Flow

Growth in

Shareholder

Value

Upstream Overview

Analyst Meeting

March 8, 2006

2005 Highlights

•

Record earnings

$24.3 B

•

ROCE

46 %

•

Production volumes

4.1 MOEBD

•

Resource adds

4.4 BOEB

•

Proved reserves adds

1.7 BOEB

•

Capex

$14.5 B

Upstream

Upstream Strategies

•

Identify

and

pursue

all

attractive

exploration

opportunities

•

Invest

projects

that

deliver

superior

returns

•

Maximize

profitability

existing

oil

and

gas

production

•

Capitalize

growing

natural

gas

and

power

markets

Upstream

Business Approach

Upstream

Operational

Excellence

Disciplined

Investment

Industry

Leading

Returns

Superior

Cash Flow

Growth in

Shareholder

Value

Large, High-Quality

Resource Base

Attractive Project

Portfolio

Superior Project

Management

Maximum Value from

Production Assets

Proprietary Technology

Development and

Deployment

Industry-Leading

Returns

Competitive Advantages

Through the

Asset Lifecycle

Superior Size and Quality

Resource Type

Upstream: Large, High-Quality Resource Base

LNG

Tight Gas

Conventional

Deepwater

Arctic

Heavy Oil

Acid/Sour

Gas

Total Resource Base

Americas

Europe

Russia/Caspian

Africa

BOEB

Asia Pacific/

Middle East

BOEB

YE '05

Kearl

Fort Hills

Joslyn

Horizon

Kearl

Fort Hills

Joslyn

Horizon

Quality Heavy Oil Resources –

Kearl

Resource Quality

BOEB

Total Volume: Bitumen-in-place

Resource Size

Horizon

Fort

Hills

Upstream: Large, High-Quality Resource Base

Joslyn

XOM

Competitors

0.0

0.2

0.4

0.6

0.8

'01

'02

'03

'04

'05

5 Yr

'01

'02

'03

'04

'05

5 Yr

Brazil

Norway

Angola

Nigeria

Chad

U.K.

Kazakhstan

Adding to the Resource Base

Annual Resource Additions

Average Annual Finding and

Resource Acquisition Costs

BOEB

$/OEB

Qatar

2005 Resource Adds

Australia

Upstream: Large, High-Quality Resource Base

Canada

Avg.

United

States

Adding to the Resource Base –

2006/07 Exploration

Upstream: Large, High-Quality Resource Base

Madagascar-

Majunga

Block

Canada-Orphan Basin

Norway-Kogge

Kazakhstan-

Ansagan

U.S.-Blackbeard

Colombia-Tayrona

Block

100

'01

'02

'03

'04

'05

Industry-Leading Reserves

XOM Proved Reserves Replacement

Upstream: Large, High-Quality Resource Base

XOM YE’05 Proved Reserves by Region

Americas

Europe

Asia Pacific/

Middle East

Africa

Russia/Caspian

(Including asset sales, excluding YE pricing)

BOEB

Yrs

Remaining

14.5

12.3

9.5

13.6

BOEB

Proved Reserves* (YE 2005)

ExxonMobil reserves includes year-end price/cost revisions and Canadian tar sands operations

Competitor data estimated using a consistent basis with ExxonMobil, and based on public information

XOM

RDS

CVX

2005 Major Project Start-Ups

Upstream: Attractive Project Portfolio

Kizomba B

Azeri-Chirag-Gunashli

Phase 1

Bonga

Kristin

RasGas Train 4

Sakhalin-1

Phase 1

Arthur

Al Khaleej

Gas Phase 1

2005

Year

Cumulative

Start-Ups

2006 Major Project Start-Ups

Upstream: Attractive Project Portfolio

Dalia

Erha & Erha North

Fram East

Syncrude

Upgrader

Expansion

Guntong Hub

Thunder Horse

East Area Additional

Oil Recovery

2005

2006

Year

Cumulative

Start-Ups

Azeri-Chirag-Gunashli

Phase 2

2007/2008 Major Project Start-Ups

Upstream: Attractive Project Portfolio

2005

2006

Year

Cumulative

Start-Ups

Qatargas II Train 4

Kizomba C

East Area Natural

Gas Liquids

PBU Western Region Dev. (Orion)

RasGas Train 6

Rosa Area

Tengiz Phase 1

RasGas Train 5

Volve

Statfjord

Late Life

Ormen

Lange

Piceance

Tight

Gas Phase 1

Starling

Azeri-Chirag-Gunashi

Phase 3

2007/‘08

2009+ Major Project Start-Ups

Upstream: Attractive Project Portfolio

Skarv/Idun

Tyrihans

Tempa

Rossa

Hebron

Alaska Gas Project/

Point Thomson

Mackenzie Gas Project

Kearl

Phase 1

Kearl

(Future Phases)

Piceance

Tight

Gas Phase 2

Kashagan Phase 1

Kashagan (Future Phases)

Tengiz Expansion

Al Khaleej

Gas (Future Phases)

RasGas Train 7

Qatargas II Train 5

Qatar GTL

Sakhalin-1 Gas

Export

Natuna

PNG Gas

Project

Paz Flor

Lirio-Cravo

Kizomba D

Angola LNG

Bonga Ullage

Bonga SW

Bosi

Oil

Usan

Satellite Projects

LNG IPP Project

Greater Gorgon

Banyu Urip

2005

2006

2009+

Year

Cumulative

Start-Ups

Kipper/Tuna

2007/‘08

Strong Project Inventory

# of Projects

Planning

Designing

Implementing

Start-up

Upstream: Attractive Project Portfolio

Project

Phase

•

Inventory develops

26 BOEB (net)

•

Designing,

implementing,

and start-up projects

50% increase in

number of projects

since 2001

Average development

cost of $3/OEB gross

120

'01

'02

'03

'04

'05

Adding Quality Extended-Plateau Capacity

Upstream: Attractive Project Portfolio

•

Over 2 MOEBD capacity

to be added by 2015

•

65% of new capacity

from extended-plateau

flowstreams

2006

2015

MOEBD-Net

2.5

2.0

1.5

1.0

0.5

Extended-

Plateau

Flowstreams

2005-2015 Major Project Start-Ups

Conventional

Decline

Flowstreams

Leading Industry in Large Project Execution

* RDS, BP, CVX

Upstream: Superior Project Management

Operated Projects > $1 Billion, Start-Up 2005-2008

$/OEB

Cost Growth (since 1Q 2005)

Development Cost

XOM

Competitors*

XOM

Competitors*

Sources: Wood Mackenzie, public information and project owner data

Execution Excellence -

Deepwater Angola

•

Design One, Build Multiple

•

Established new worldwide

benchmark for cycle time

•

Achieved production rates

at or above expectations

•

Utilized tension leg

platforms for cost effective well

intervention

•

Developing Kizomba C

Upstream: Superior Project Management

Block 15 Production Build-Up

KBD-Gross

‘03

‘04

‘05

‘06

Kizomba

Kizomba A

Xikomba

2003 Planning

Outlook

200

400

600

Execution Excellence -

Sakhalin 1

•

Phased approach

•

World-class extended-reach

drilling performance

•

On-schedule start-up in

October 2005

•

Onshore production facility

start-up YE 2006

Upstream: Superior Project Management

XOM

Competitors

100

200

300

400

500

600

700

Extended-Reach Wells

Rate (feet/day)

Vertical Depth (K feet)

Reach (K feet)

Chayvo

'03

'04

'05

'06

'07

'08

'09

'10

Execution Excellence -

Qatar LNG

MTA-Gross

LNG Train Capacity Growth

Conventional

LNG

Large

LNG

Larger

Trains

Larger

Ships

Terminal

Upstream: Superior Project Management

LNG from XOM-Interest Trains

RasGas 1-2

RasGas 3

RasGas 5

RasGas 6

Qatargas 4

Qatargas 5

RasGas 7

Qatargas 1-3

RasGas 4

Cost of Service

100

MTA-Gross

Qatar LNG Trains

‘69

‘77

‘83

‘96

‘04

‘05

‘08

Major train size increases –

Start-Up year

Qatargas II Train 4

RasGas Train 6

Funded

Operating

Pursuing Gas and Power Opportunities

Qatar

Gorgon/

Jansz

PNG

Mackenzie

Alaska

Sakhalin-1

Hong Kong

Upstream

Natuna

Power

LNG

Pipeline-Gas

LNG Terminals

Gas-To-Liquids

Angola

Nigeria

U.K.

Italy

U.S. Gulf Coast

* Competitor data estimated using a consistent basis with ExxonMobil,

and based on public information

2005

Industry-Leading Earnings per Barrel

$/OEB

2001-2005 Earnings per Barrel*

Upstream: Maximum Value from Production Assets

Capturing Value Across the Cycle

XOM Normalized Earnings per Barrel, prior 24 quarters

Production-Weighted Marker Price ($)

$/OEB

XOM

RDS

CVX

R²

= 0.991

2001-2005 Non-Project Drilling*

MOEBD-Net

Improving Recovery with Quality Drilling Programs

•

43 rigs operating

•

$2.2B investment

•

160 KOEBD first-year

production

•

Revisions/improved

recovery reserve adds

of 500 MOEB

Upstream: Maximum Value from Production Assets

* Cumulative production contribution from all non-project drill wells since January 1, 2001

2001-2005 Annual Average

0.0

0.5

1.0

'01

'02

'03

'04

'05

Enhancing Recovery with Technology

Industry EOR Projects

Light

Oil

Heavy

Oil

XOM

Participation

XOM

Participation

•

Systematic approach to

EOR evaluation

•

Industry leader in EOR

technology and experience

•

Proprietary next-generation

reservoir

simulator

–

Power

Significant 2005 Production

Under evaluation

Other EOR experience

Upstream: Maximum Value from Production Assets

ExxonMobil EOR Experience

Capturing Value with Divestments

•

Approximately 2% of YE 2005

production/reserves sold

•

Lower profitability, limited

potential assets

•

Capitalized on strong market

$4.6 B cash

$0.8 B earnings

Total Expenses

Field Life (R/P)

Production

Proved

Reserves

$/OEB

Years

2001-2005 Asset Sales

Average 2005

(KOEBD)

Year-end 2005

(MOEB)

Upstream: Maximum Value from Production Assets

Assets

Divested

2001-2005

Remaining

Assets

Unlocking Tight Gas

Piceance

Basin

Upstream: Proprietary Technology

XOM Technology

Conventional Approach

1.0

0.8

0.6

0.4

0.2

•

Over 1600 zones fractured

Currently at 45 zones/well

•

55 mcfd initial field development

•

Technology licensed to major

service providers

Piceance

Basin Development

Just-in-Time

Perforating

Annular Coiled

Tubing Fracturing

Breakthrough Technology

Colorado

Uinta Basin

Green River

Basin

Utah

Wyoming

Piceance

Basin

Well Productivity

Cumulative Production (Bcf)

100

200

300

400

500

Producing Time (days)

Drilling Wells Faster

Before

After

100% Performance

Improvement

Capture

Learnings &

Transfer

Globally

Analyze & Identify

Limits

Design to

Overcome

Limits

Real-Time Energy

Based Analysis

Real-Time

Redesign

Fast Drill

Workflow

Analyze, Drill, Redesign, Repeat ...

Upstream: Proprietary Technology

•

Real-time, rig-centered

•

Brings

science

closer to operations

•

Wells drilled up to 35%

faster

Fast Drill Process

Integrating Best-In-Class Technologies

Upstream: Proprietary Technology

Basin

modeling

Seismic imaging

& processing

Commercializing

the Resource

Maximizing

Ultimate Value

Enhanced Recovery

100

150

1970

1980

1990

2000

2010

2020

2030

Developed Capacity

History/Prediction

Understanding the Subsurface

Optimizing the

Development

Reservoir

simulation

Geologic modeling

Visualization

'05

'06

'07

'08

'09

'10

Delivering Profitable Capacity Growth

•

Result of robust inventory

and strong processes

•

Geographically diverse

•

Enabled by functional expertise,

integrated and leveraged

worldwide

•

Delivering on our strategies

Upstream: Summary

MOEBD

Americas

Europe

Asia Pacific/

Middle East

Africa

Industry-Leading Performance

2001-2005 Return on Average Capital Employed*

•

Large, high-quality resource

base

•

Attractive project portfolio

•

Superior project

management

•

Maximum value from production

assets

•

Proprietary technology

2005

Upstream: Summary

* Competitor data estimated using a consistent basis with ExxonMobil,

and based on public information

XOM

RDS

CVX

Downstream Overview

Analyst Meeting

March 8, 2006

•

Record financial performance

Earnings

$8 B

ROCE

32 %

Refinery throughput

5.7 MBD

Petroleum

product

sales

8.3

MBD

•

Operational excellence continues

Safety and environmental

Reliability

Energy efficiency

•

Strategic initiatives delivering

More than $1B “self-help”

each year

2005 Highlights

Downstream

Refining & Supply

Lubes Marketing

Fuels Marketing

Business Strategies

•

Maintain best-in-class operations, in all respects

•

Provide quality, valued products and services to customers

•

Lead industry in efficiency and effectiveness

•

Capitalize on integration with other ExxonMobil businesses

•

Selectively invest for resilient, advantaged returns

•

Maximize value from leading-edge technology

Downstream

Business Approach

Downstream

Operational

Excellence

Disciplined

Investment

Industry

Leading

Returns

Superior

Cash Flow

Growth in

Shareholder

Value

Asset

Utilization

Project

Execution

Raw Material

Flexibility

Structural

Advantages

Operating

Efficiencies

Global Scale

& Integration

Margin

Enhancement

Technology

Leadership

Industry-Leading

Returns

Americas

16 Refineries

Europe/AME

18 Refineries

Asia-Pacific

11 Refineries

•

Largest global refiner

•

Largest global supplier & marketer of petroleum products

•

Largest manufacturer & marketer of lube basestocks

•

Largest global producer of polyolefins, benzene & paraxylene

Global Scale and Integration

Downstream

Average Refinery

Size

KBD

Source: Equity capacity calculated on consistent basis using public information

Integration with

Chemicals or Lubes

Capacity and

Geographic Mix

MBD

Refining Structural Advantages

Downstream

XOM

RDS

Industry

XOM

RDS

Industry

XOM

RDS

Americas

EAME

100

150

200

250

Fuels Marketing Structural Advantages

Global Fuel Sales

Downstream

•

Largest supplier & marketer

of petroleum products

•

Leveraging integration with

refining

•

Broad spectrum of customer

channels

•

Product placement for

highest value

I&W Sales

20%

Retail Sales

30%

Aviation &

Marine Sales

10%

Refining &

Supply Sales

40%

KBD

Lubes Marketing Structural Advantages

Market Share

•

Largest manufacturer and

marketer of lube basestocks

•

Leveraging integration with

refining

•

Strong OEM relationships

•

Technically advanced products

Downstream

XOM

RDS

Basestocks

Finished Lubricants

Conversion Capacity Growth

Source: EM / O&GJ, 100% basis

Distillation Capacity Growth

~50 KBD

per year

~35 KBD

per year

“Equivalent to a new

refinery every 3 years”

KBD

Self-Help: Economic Refining Growth

Downstream

100

200

300

400

'95

'00

'05

200

400

600

'95

'00

'05

100

105

110

'00

'01

'02

'03

'04

'05

Raw Material Flexibility

Crude Runs, Indexed

Challenged

Crudes

Source: EM, Solomon

Self-Help: Refining Margin Enhancement

Downstream

Crude API Gravity

Higher Value Products

XOM

Industry

Clean Product Yield, Indexed

Crude Sulfur

Lower Crude Costs

Crude Quality, Indexed

* 2005 Estimated –

Solomon survey only

prepared in even years

100

110

120

130

140

150

160

170

'00

'01

'02

'03

'04

'05

100

102

'00

'02

'04

'05*

250

500

750

'02

'03

'04

'05

'06

'07

'08

Self-Help: Refining Margin Enhancement

Downstream

Molecule Management

$M/Year, Cumulative before-tax

•

Molecular fingerprinting

•

Process modeling

•

Process control and

optimization

•

Scheduling & blending

Energy Index

Indexed

Personnel Index

Source: Solomon

Industry

Self-Help: Refining Operating Efficiency

Downstream

Unit Cash Cost

Industry

Indexed

* 2005 Estimated –

Solomon survey only prepared in even years

XOM

100

102

104

'00

'02

'04

'05

100

110

120

130

'00

'02

'04

'05

100

105

110

115

'00

'02

'04

'05

100

110

'00

'01

'02

'03

'04

'05

Capacity Utilization

XOM

Industry

Throughput

Unplanned Lost

Capacity

Reliability

Indexed

XOM

Indexed

Self-Help: Refining Asset Utilization

Downstream

Source: EM, Solomon

* 2005 Estimated –

Solomon survey only prepared in even years

100

102

'00

'02

'04

'05*

100

110

'01

'02

'03

'04

'05

100

110

120

'01

'02

'03

'04

'05

Self-Help: Retail Marketing

No. of Retail

Sites

Fuel Sales per

Site

$M*, Improvement Since 2000

Asset Utilization

Nonfuels

Income Growth

Breakeven Fuels Margin

Indexed

Downstream

U.S., Indexed

* Before-tax

100

150

200

'01

'02

'03

'04

'05

Self-Help: Lubes Marketing

Downstream

XOM

Industry*

Operating Efficiencies

Flagship Products

Indexed

Growth Markets

Indexed

Workforce

Blend Plants

Order

Centers

Product

Complexity

XOM

Industry*

(Finished Lube Sales)

* ExxonMobil estimate

100

'01

'02

'03

'04

'05

100

125

150

'01

'02

'03

'04

'05

100

125

150

'01

'02

'03

'04

'05

Erosion Resistant Materials

Advanced Catalysis

Fouling Inhibition Technology

Equipment Health Monitoring

Flagship

Lube

Products

–

Mobil

Process Modeling & Optimization Tools

Plant Automation

Molecule Management

Crude Contaminant Control

Fiber Optic Corrosion Sensors

Coke Morphology

Slurry Decoking Throttling Valve

Higher Value Products

Improve Efficiency

Higher Reliability

Asset Utilization

Higher Yields

Upgrade Products

Increase Margin

Lower Crude Costs

Capacity Utilization

Molecular Optimization

Raw Material Flexibility

Lower Costs

Focus Areas

Strategic Objectives

R&D Programs

Technology Leadership

Downstream

Self-Help

2000

2005

$8.0B

$3.4B

Industry

Margins

Earnings

Inflation

Forex

Self-Help Drives Earnings Growth

Downstream

Industry-Leading Returns

Downstream

Average Capital Employed*

XOM

RDS

‘00 ‘05

‘00

‘05

‘00

‘05

Return on Average Capital Employed*

Reported Net Income

‘00 ‘05

‘00

‘05 ‘00‘05

*Competitor data estimated using a consistent basis with ExxonMobil, and based on public information

‘00 ‘05

Chemical Overview

Analyst Meeting

March 8, 2006

2005 Highlights

•

Earnings of $3.9B, ROCE of 28%

Global scale and integration

Feedstock flexibility

Successful margin enhancement

•

Operational excellence continues

Safety

Reliability

Energy efficiency

•

Capex of $654M

High return efficiency projects

Low-cost expansions

Specialty business growth

Chemical

Business Strategies

Long-term strategy built on ExxonMobil’s core competencies

•

Unique portfolio of global integrated businesses

•

Integration across ExxonMobil operations

•

Focus on cost management, reliability and efficiencies

•

Disciplined investment in advantaged projects

•

Technology leadership

Business Approach

Chemical

Operational

Excellence

Disciplined

Investment

Industry

Leading

Returns

Superior

Cash Flow

Growth in

Shareholder

Value

Asset

Utilization

Advantaged

Projects

Advantaged

Feedstocks

Unique Business

Portfolio

Cost

Management

Global Scale

& Integration

Premium

Products

Technology

Leadership

Industry-Leading

Returns

Unique Portfolio of Businesses

Aromatics

Olefins

Polyethylene

Polypropylene

Specialty Businesses

Commodity Businesses

ExxonMobil Chemical Earnings

Chemical

Rank*

*Based on worldwide market position

Butyl

Fluids

Oxo

Synthetics

Films

Adhesion

Ethylene Elastomers

Additives

0.0

1.0

2.0

3.0

4.0

'95

'00

'05

Long-Standing Integration Advantage

Petrochemical

Plant

Crude Oil

and

Feedstocks

Gas Processing

Natural

Gas

Chemical

Refinery

Integration Benefits

•

Advantaged feed access

•

Molecule optimization

•

Energy integration

•

Coordinated planning

•

Shared site services

•

Common processes

•

Research & Technology

Positioned for Asia Pacific Growth

•

Existing advantaged asset base

Feedstock

Integration

Market access

•

Pursuing additional advantaged

opportunities

Chemical

Major Project Opportunities

Existing

Announced

XOM BP RDS Dow

Singapore

Fujian

Ras Laffan

Asia Pacific/Middle East Capacities

Singapore Expansion Project

Refinery

Chemical

Singapore

Steam

Cracker

Arom

Oxo

Fluids

Singapore

#2 Steam

Cracker

Arom

Elast

Chemical Plant

Existing Plant

Proposed Project

Oxo

Improvement via Self-Help

Energy

Indexed

Cumulative MT vs 2001

Reliability Gains

Advantaged Feedstocks

Workforce

Chemical

Indexed

Steamcracking

Other Operations

Indexed

100

120

'02

'05

100

'02

'05

'02

'05

100

'02

'05

0.0

0.5

1.0

1.5

'02

'03

'04

'05

Heavy Steam Cracker Feeds

Gas-to-Olefins

New Aromatics Feeds

Synthetics Feed Flexibility

Premium Products

Zeolite Catalyst Extensions

Butyl Mercury

In-Reactor Compounds

Unipol

Fundamentals

Step-Skipping

Step-Out Economics

Reduced Cost

Specialties Growth

Higher/Stable Returns

Differentiation

Refining Synergies

Gas-to-Chemical

Feed Flexibility

Advantaged Feed

Lower Cost Process

Novel Elastomers & Adhesives

Improved Stiffness / Toughness Balance

Nanocomposite

Materials

Achieve™

Meltblown

Focus Areas

Strategic Objectives

R&D Programs

Technology Leadership

Chemical

Delivering Superior Returns

Average Capital Employed*

Reported Net Income

Return on Average Capital Employed*

XOM

RDS

CVX

Dow

*Competitor data estimated using a consistent basis with ExxonMobil, and based on public information

Chemical

‘00

‘05

‘00

‘05

‘00

‘05

‘00

‘05

‘00 ‘05

‘00

‘05

‘00

‘05

‘00

‘05

‘00 ‘05

‘00

‘05

‘00

‘05

‘00

‘05

Summary

Analyst Meeting

March 8, 2006

Industry Environment

•

Growing demand for energy; nearly 50 percent

increase by 2030

•

Technology and investment critical to meeting

future energy needs

•

Long-term capital intensive industry

•

Industry driven by long-term trends

Industry Challenges Play to our Strengths

•

Global functional organization, scale, and

geographic diversity

•

Unmatched financial and technology strength

•

Industry-leading resource base and project portfolio

•

Integration of Downstream and Chemical

•

Superior business approach and execution

ExxonMobil Superior Business Approach

•

Staying the course

•

Building our advantages

•

Growing shareholder value

Disciplined

Investment

Operational

Excellence

Industry

Leading

Returns

Superior

Cash Flow

Growth in

Shareholder

Value

Additional Information

Analyst Meeting

March 8, 2006

100

150

200

'90

'95

'00

'05

'10

Industry Environment

The Industry Cycle*

Margin Trends*

* ExxonMobil Estimates

Nominal $

Polyethylene, Polypropylene, Paraxylene

Rest of

World

Capacity

Utilization

Chemical

Asia Pacific

Demand

500

1000

'90

'95

'00

'05

Frequently Used Terms and additional information

Exhibit 99.3

Frequently Used Terms

Listed below are definitions of several of ExxonMobil’s key business and financial performance measures and other terms. These definitions are provided to facilitate understanding of the terms and their calculation. In the case of financial measures that we believe constitute “non-GAAP financial measures” under Securities and Exchange Commission Regulation G, we provide a reconciliation to the most comparable Generally Accepted Accounting Principles (GAAP) measure and other information required by that rule.

EARNINGS EXCLUDING MERGER EXPENSES, DISCONTINUED OPERATIONS, ACCOUNTING CHANGE, AND OTHER SPECIAL ITEMS

In addition to reporting U.S. GAAP defined net income, ExxonMobil also presents a measure of earnings that excludes merger effects, earnings from discontinued operations, a required accounting change, and other special items quantified and described in our quarterly and annual earnings press releases. Earnings excluding the aforementioned items is a non-GAAP financial measure, and is included to facilitate comparisons of base business performance across periods. A reconciliation to net income is shown on page 5. We also refer to earnings excluding merger expenses, discontinued operations, accounting changes, and other special items as normalized earnings. Earnings per share amounts use the same average common shares outstanding as used for the calculation of net income per common share and net income per common share – assuming dilution.

OPERATING COSTS

Operating costs are the combined total of production, manufacturing, selling, general, administrative, exploration, depreciation, and depletion expenses from the Consolidated Statement of Income and ExxonMobil’s share of similar costs for equity companies. Operating costs are the costs during the period to produce, manufacture, and otherwise prepare the company’s products for sale – including energy costs, staffing, maintenance, and other costs to explore for and produce oil and gas, and operate refining and chemical plants. Distribution and marketing expenses are also included. Operating costs exclude the cost of raw materials, taxes, merger expenses, discontinued operations, and interest expense. These expenses are on a before-tax basis. While ExxonMobil’s management is responsible for all revenue and expense elements of net income, operating costs, as defined below, represent the expenses most directly under management’s control. Information regarding these costs is therefore useful for investors and ExxonMobil management in evaluating management’s performance.


Reconciliation of Operating Costs

*(millions of dollars)*	2005	2004	2003
From ExxonMobil’s Consolidated Statement of Income
Total costs and other deductions	311,248	256,794	214,772
Less:
Crude oil and product purchases	185,219	139,224	107,658
Interest expense	496	638	207
Excise taxes	30,742	27,263	23,855
Other taxes and duties	41,554	40,954	37,645
Income applicable to minority and preferred interests	799	776	694

Subtotal	52,438	47,939	44,713
ExxonMobil’s share of equity-company expenses	4,520	4,209	3,937

Total operating costs	56,958	52,148	48,650


Components of Operating Costs

*(millions of dollars)*	2005	2004	2003
From ExxonMobil’s Consolidated Statement of Income
Production and manufacturing expenses	26,819	23,225	21,260
Selling, general, and administrative expenses	14,402	13,849	13,396
Depreciation and depletion	10,253	9,767	9,047
Exploration expenses, including dry holes	964	1,098	1,010

Subtotal	52,438	47,939	44,713
ExxonMobil’s share of equity-company expenses	4,520	4,209	3,937

Total operating costs	56,958	52,148	48,650

- 1 -

CAPITAL EMPLOYED

Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it includes ExxonMobil’s net share of property, plant, and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the Corporation, it includes ExxonMobil’s share of total debt and shareholders’ equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed.


*(millions of dollars)*	2005		2004		2003
Business uses: asset and liability perspective
Total assets	208,335		195,256		174,278
Less liabilities and minority share of assets and liabilities
Total current liabilities excluding notes and loans payable	(44,536	)	(39,701	)	(33,597	)
Total long-term liabilities excluding long-term debt and equity of minority and preferred shareholders in affiliated companies	(41,095	)	(41,554	)	(37,839	)
Minority share of assets and liabilities	(4,863	)	(5,285	)	(4,945	)
Add ExxonMobil share of debt-financed equity-company net assets	3,450		3,914		4,151

Total capital employed	121,291		112,630		102,048


Total corporate sources: debt and equity perspective
Notes and loans payable	1,771		3,280		4,789
Long-term debt	6,220		5,013		4,756
Shareholders’ equity	111,186		101,756		89,915
Less minority share of total debt	(1,336	)	(1,333	)	(1,563	)
Add ExxonMobil share of equity-company debt	3,450		3,914		4,151

Total capital employed	121,291		112,630		102,048

RETURN ON AVERAGE CAPITAL EMPLOYED (ROCE)

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

Return on Average Capital Employed


*(millions of dollars)*	2005		2004		2003
Net income	36,130		25,330		21,510
Financing costs (after tax)
Third-party debt	(1	)	(137	)	(69	)
ExxonMobil share of equity companies	(144	)	(185	)	(172	)
All other financing costs – net	(295	)	54		1,775	(1)

Total financing costs	(440	)	(268	)	1,534

Earnings excluding financing costs	36,570		25,598		19,976

Average capital employed	116,961		107,339		95,373
Return on average capital employed – corporate total	31.3	%	23.8	%	20.9	%

(1)	“All other financing costs – net” in 2003 includes interest income (after tax) associated with the settlement of a U.S. tax dispute.

- 2 -

TOTAL SHAREHOLDER RETURN

Shareholder return measures the change in value of an investment in stock over a specified period of time, assuming dividend reinvestment. We calculate shareholder return over a particular measurement period by: dividing (1) the sum of (a) the cumulative value of dividends received during the measurement period, assuming reinvestment, plus (b) the difference between the stock price at the end and at the beginning of the measurement period; by (2) the stock price at the beginning of the measurement period. For this purpose, we assume dividends are reinvested in stock at market prices at approximately the same time actual dividends are paid. Shareholder return is usually quoted on an annualized basis.

CAPITAL AND EXPLORATION EXPENDITURES (CAPEX)

Capital and exploration expenditures (Capex) are the combined total of additions at cost to property, plant, and equipment and exploration expenses on a before-tax basis from the Consolidated Statement of Income. ExxonMobil’s Capex includes its share of similar costs for equity companies. Capex excludes depreciation on the cost of exploration support equipment and facilities recorded to property, plant, and equipment when acquired. While ExxonMobil’s management is responsible for all investments and elements of net income, particular focus is placed on managing the controllable aspects of this group of expenditures.

FINDING AND RESOURCE-ACQUISITION COSTS

Finding and resource-acquisition costs per oil-equivalent barrel is a performance measure that is calculated using the Exploration portion of Upstream capital and exploration expenditures and proved property acquisition costs divided by resource additions (in oil-equivalent barrels). ExxonMobil refers to new discoveries and acquisitions of discovered resources as resource additions. In addition to proved reserves, resource additions include quantities of oil and gas that are not yet classified as proved reserves, but which ExxonMobil believes will likely be moved into the proved reserves category and produced in the future.


	2005	2004	2003
Exploration portion of Upstream capital and exploration expenditures (millions of dollars)	1,693	1,283	1,215
Proved property acquisition costs (millions of dollars)	174	93	—
Total exploration and proved property acquisition costs (millions of dollars)	1,867	1,376	1,215
Resource additions (millions of oil-equivalent barrels)	4,365	2,950	2,115
Finding and resource-acquisition costs per oil-equivalent barrel (dollars)	0.43	0.47	0.57

LIQUIDS AND NATURAL GAS PROVED RESERVES

In this report, we use the term “proved reserves” to mean quantities of oil and gas that ExxonMobil has determined to be reasonably certain of recovery under existing economic and operating conditions on the basis of our long-standing, rigorous management review process. We only book proved reserves when we have made significant funding commitments for the related projects. In this report, we aggregate proved reserves of consolidated and equity companies, excluding royalties and quantities due others, since ExxonMobil does not view these reserves differently from a management perspective. To reflect management’s view of ExxonMobil’s total liquids reserves, proved reserves in this report also include tar-sands reserves from Canadian Syncrude operations, which are reported separately as mining reserves in our SEC filings. Tar-sands reserves included in this report totaled 738 million barrels at year-end 2005, 757 million barrels at year-end 2004, 781 million barrels at year-end 2003, 800 million barrels at year-end 2002, and 821 million barrels at year-end 2001. For our own management purposes and as discussed in this report, we determine proved reserves based on our long-term view of future price levels consistent with our investment decisions. Based on Securities and Exchange Commission guidance, ExxonMobil also began in 2004 to state our results to reflect the impacts on proved reserves of utilizing December 31 liquids and natural gas prices (“year-end price/cost revisions”). On this basis, year-end proved reserves, including year-end price/cost revisions, totaled 22.4 billion oil-equivalent barrels in 2005 and 21.7 billion oil-equivalent barrels in 2004. Excluding year-end price/cost revisions, 2005 proved reserves also totaled 22.4 billion oil-equivalent barrels, while 2004 proved reserves totaled 22.2 billion oil-equivalent barrels.

RESOURCES, RESOURCE BASE, AND RECOVERABLE RESOURCES

Resources, resource base, recoverable oil, recoverable hydrocarbons, recoverable resources, and similar terms used in this report are the total remaining estimated quantities of oil and gas that are expected to be ultimately recoverable. In addition to proved reserves, the resource base includes quantities of oil and gas that are not yet classified as proved reserves, but which ExxonMobil believes will likely be moved into the proved reserves category and produced in the future.

PROVED RESERVES REPLACEMENT RATIO

Proved reserves replacement ratio is a performance measure that is calculated using proved oil-equivalent reserves additions divided by oil-equivalent production. Both proved reserves additions and production include amounts applicable to equity companies. The ratio usually reported by ExxonMobil excludes sales and year-end price/cost revisions, and includes Canadian tar-sands mining operations in both additions and production volumes. See the definition of “liquids and natural gas proved reserves” above. When reporting the ratio, the inclusions and exclusions are listed, as appropriate.

- 3 -

PROVED RESERVES REPLACEMENT COSTS

Proved reserves replacement costs per oil-equivalent barrel is a performance measure ratio. Proved reserves replacement costs per barrel are costs incurred in property acquisition and exploration, plus costs incurred in development activities divided by proved oil-equivalent reserves additions, excluding sales. Both the costs incurred and the proved reserves additions include amounts applicable to equity companies as well as Canadian tar-sands operations and exclude year-end price/cost revisions. See the definition of “liquids and natural gas proved reserves” on the preceding page.


*(millions of dollars)*	2005	2004	2003
Costs incurred
Property acquisition costs	453	134	45
Exploration costs	1,420	1,255	1,181
Development costs	10,561	9,122	9,856
Total costs incurred	12,434	10,511	11,082


*(millions of barrels)*	2005	2004	2003
Proved oil-equivalent reserves additions
Revisions	377	140	619
Improved recovery	31	28	116
Extensions/discoveries	1,461	1,809	961
Purchases	122	11	2
Total oil-equivalent reserves additions	1,991	1,988	1,698


Proved reserves replacement costs	6.25	5.29	6.53

HEAVY OIL

Heavy oil, for the purpose of this report, includes heavy oil, extra heavy oil, and bitumen, as defined by the World Petroleum Congress in 1987 based on API gravity and viscosity at reservoir conditions. Heavy oil has an API gravity between 10 and 22.3 degrees. The API gravity of extra heavy oil and bitumen is less than 10 degrees. Extra heavy oil has a viscosity less than 10 thousand centipoise, whereas the viscosity of bitumen is greater than 10 thousand centipoise. The term “tar sands” is used to indicate heavy oil (generally bitumen) that is recovered in a mining operation.

CASH FLOW FROM OPERATIONS AND ASSET SALES

Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds from sales of subsidiaries, investments, and property, plant, and equipment from the Summary Statement of Cash Flows. This cash flow is the total sources of cash from both operating the Corporation’s assets and from the divesting of assets. The Corporation employs a long-standing and regular disciplined review process to ensure that all assets are contributing to the Corporation’s strategic and financial objectives. Assets are divested when they are no longer meeting these objectives, or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.


*(millions of dollars)*	2005	2004	2003
Net cash provided by operating activities	48,138	40,551	28,498
Sales of subsidiaries, investments and property, plant, and equipment	6,036	2,754	2,290

Cash flow from operations and asset sales	54,174	43,305	30,788

DISTRIBUTIONS TO SHAREHOLDERS

The Corporation distributed cash to shareholders in the form of both dividends and share purchases. Shares are purchased both to reduce shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. For purposes of calculating distributions to shareholders, the Corporation only includes the cost of those shares purchased to reduce shares outstanding.


*(millions of dollars)*	2005	2004	2003
Dividends paid to ExxonMobil shareholders	7,185	6,896	6,515
Cost of shares purchased to reduce shares outstanding	16,000	8,000	5,000

Distributions to ExxonMobil shareholders	23,185	14,896	11,515

Memo: Gross cost of shares purchased to offset shares issued under benefit plans and programs	2,221	1,951	881

- 4 -

Exxon Mobil Corporation

FUNCTIONAL EARNINGS


	2005 Quarters
*(millions of dollars)*	First		Second		Third		Fourth	2005		2004		2003		2002		2001
Net Income (U.S. GAAP)
Upstream
United States	1,353		1,389		1,671		1,787	6,200		4,948		3,905		2,524		3,933
Non-U.S.	3,701		3,519		5,678		5,251	18,149		11,727		10,597		7,074		6,803

Total	5,054		4,908		7,349		7,038	24,349		16,675		14,502		9,598		10,736
Downstream
United States	645		999		1,109		1,158	3,911		2,186		1,348		693		1,924
Non-U.S.	808		1,022		1,019		1,232	4,081		3,520		2,168		607		2,303

Total	1,453		2,021		2,128		2,390	7,992		5,706		3,516		1,300		4,227
Chemical
United States	492		343		70		281	1,186		1,020		381		384		298
Non-U.S.	940		471		402		944	2,757		2,408		1,051		446		409

Total	1,432		814		472		1,225	3,943		3,428		1,432		830		707
Corporate and financing	(79	)	(103	)	(29	)	57	(154	)	(479	)	1,510		(442	)	(142	)
Merger expenses	0		0		0		0	0		0		0		(275	)	(525	)
Discontinued operations	0		0		0		0	0		0		0		449		102
Extraordinary gain	0		0		0		0	0		0		0		0		215
Accounting change	0		0		0		0	0		0		550		0		0

Net income (U.S. GAAP)	7,860		7,640		9,920		10,710	36,130		25,330		21,510		11,460		15,320

Net income per common share (dollars)	1.23		1.21		1.60		1.72	5.76		3.91		3.24		1.69		2.23
Net income per common share - assuming dilution (dollars)	1.22		1.20		1.58		1.71	5.71		3.89		3.23		1.68		2.21

Merger Effects, Discontinued Operations, Accounting Change, and Other Special Items

Upstream
United States	0		0		0		0	0		0		0		0		0
Non-U.S.	0		0		1,620		0	1,620		0		1,700		(215	)	0

Total	0		0		1,620		0	1,620		0		1,700		(215	)	0
Downstream
United States	0		(200	)	0		0	(200	)	(550	)	0		0		0
Non-U.S.	310		0		0		0	310		0		0		0		0

Total	310		(200	)	0		0	110		(550	)	0		0		0
Chemical
United States	0		0		0		0	0		0		0		0		0
Non-U.S.	150		0		0		390	540		0		0		0		0

Total	150		0		0		390	540		0		0		0		0
Corporate and financing	0		0		0		0	0		0		2,230		0		0
Merger expenses	0		0		0		0	0		0		0		(275	)	(525	)
Discontinued operations	0		0		0		0	0		0		0		449		102
Extraordinary gain	0		0		0		0	0		0		0		0		215
Accounting change	0		0		0		0	0		0		550		0		0

Corporate total	460		(200	)	1,620		390	2,270		(550	)	4,480		(41	)	(208	)


Earnings Excluding Merger Effects, Discontinued Operations, Accounting Change, and Other Special Items (1)

Upstream
United States	1,353		1,389		1,671		1,787	6,200		4,948		3,905		2,524		3,933
Non-U.S.	3,701		3,519		4,058		5,251	16,529		11,727		8,897		7,289		6,803

Total	5,054		4,908		5,729		7,038	22,729		16,675		12,802		9,813		10,736
Downstream
United States	645		1,199		1,109		1,158	4,111		2,736		1,348		693		1,924
Non-U.S.	498		1,022		1,019		1,232	3,771		3,520		2,168		607		2,303

Total	1,143		2,221		2,128		2,390	7,882		6,256		3,516		1,300		4,227
Chemical
United States	492		343		70		281	1,186		1,020		381		384		298
Non-U.S.	790		471		402		554	2,217		2,408		1,051		446		409

Total	1,282		814		472		835	3,403		3,428		1,432		830		707
Corporate and financing	(79	)	(103	)	(29	)	57	(154	)	(479	)	(720	)	(442	)	(142	)

Corporate total	7,400		7,840		8,300		10,320	33,860		25,880		17,030		11,501		15,528

Earnings per common share (dollars)	1.16		1.24		1.34		1.66	5.40		3.99		2.57		1.70		2.27
Earnings per common share - assuming dilution (dollars)	1.15		1.23		1.32		1.65	5.35		3.97		2.56		1.69		2.25

(1)	See Frequently Used Terms.

- 5 -

Exxon Mobil Corporation

RETURN ON AVERAGE CAPITAL EMPLOYED (1) BY BUSINESS


*(percent)*	2005	2004	2003	2002	2001
Upstream
United States	46.0	37.0	28.9	19.0	30.4
Non-U.S.	45.6	31.5	31.0	23.7	25.1
Total	45.7	32.9	30.4	22.3	26.8
Downstream
United States	58.8	28.6	16.7	8.6	25.0
Non-U.S.	22.6	18.0	11.5	3.4	12.4
Total	32.4	21.0	13.0	5.0	16.1
Chemical
United States	23.1	19.4	7.3	7.3	7.2
Non-U.S.	30.9	25.7	11.8	5.3	5.8
Total	28.0	23.5	10.2	6.1	6.4
Corporate and financing	NA	NA	NA	NA	NA
Discontinued operations	—	—	—	63.2	7.2
Corporate total	31.3	23.8	20.9	13.5	17.8

(1) Capital employed consists of shareholders’ equity and their share of consolidated debt, including ExxonMobil’s share of amounts applicable to equity companies. See Frequently Used Terms.

AVERAGE CAPITAL EMPLOYED *(1)* BY BUSINESS

*(millions of dollars)*	2005	2004	2003	2002	2001
Upstream
United States	13,491	13,355	13,508	13,264	12,952
Non-U.S.	39,770	37,287	34,164	29,800	27,077

Total	53,261	50,642	47,672	43,064	40,029
Downstream
United States	6,650	7,632	8,090	8,060	7,711
Non-U.S.	18,030	19,541	18,875	17,985	18,610

Total	24,680	27,173	26,965	26,045	26,321
Chemical
United States	5,145	5,246	5,194	5,235	5,506
Non-U.S.	8,919	9,362	8,905	8,410	8,333

Total	14,064	14,608	14,099	13,645	13,839
Corporate and financing	24,956	14,916	6,637	4,878	6,399
Discontinued operations	0	0	0	710	1,412

Corporate total	116,961	107,339	95,373	88,342	88,000


Average capital employed applicable to equity companies included above	20,256	18,049	15,587	14,001	13,902

(1) Average capital employed is the average of the beginning- and end-of-year business segment capital employed. See Frequently Used Terms.

- 6 -