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 9, 2005

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 9, 2005 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 15, 2005	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 9, 2005.
99.2	Slides presented at an analysts’ meeting held on March 9, 2005.
99.3	Frequently Used Terms and additional information.

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EX-99.1

Exhibit 99.1

Exxon Mobil Corporation

Presentations and Q&A Session

Analyst Meeting

New York, NY

March 9, 2005

EXXON MOBIL CORPORATION

Analyst Meeting

March 9, 2005

8:00 a.m. CT

Henry Hubble (Vice President of Investor Relations and Secretary):

Good morning and welcome to ExxonMobil’s analyst meeting. For those of you who I have not met, my name is Henry Hubble. I’m the Vice President of Investor Relations and Secretary of ExxonMobil.

As you know, safety is a priority for ExxonMobil, so before we begin the formal agenda, I’d like to familiarize everybody with the New York Stock Exchange’s safety procedure. There’s an exit in the back of the room, and one through the doors which you came in this morning. In the event that there is an emergency, New York Stock Exchange personnel will provide us with instructions on what to do or the best response. They will also, in case of an evacuation direct us to the nearest exit, so please wait for instructions if this occurs.

I draw your attention to the cautionary statements that you’ll find in the front of the presentation material. This statement contains information regarding today’s presentation and discussion. And I ask you, if you have not done so already to read it now. I would also refer you to our Web site, www.exxonmobil.com for additional information on factors effecting future results, as well as supplemental information defining key terms that will be used today.

Turning now to the agenda for this morning, we will begin with Lee Raymond’s remarks on the corporation’s performance. And then Rex Tillerson will present an overview of the upstream, downstream and chemicals business strategies and results. We’ll then take a short break, after which Lee will rejoin and have a few closing comments, and then we’ll open it up for your questions. We’ll end the meeting at about noon. And with that, it’s now my pleasure to introduce our Chairman and CEO, Lee Raymond.

Lee Raymond (Chairman and CEO):

Thank you, Henry. It’s a pleasure to be here today. As you probably can tell, I’m suffering from a cold, but I hope I don’t get into a coughing spell, but if I do, let me apologize ahead of time.

I want to start with reminding everyone of the long-term and cyclical nature of our industry. Our organization and our strategies are designed to see through the market noise created by short-term fluctuations. Those who don’t always keep in mind the long-term capital intensive nature of this business risk destroying shareholder value by frequent and constant major alterations to their approach.

What you will be hearing today may seem boring. You will not hear about some kind of radical restructuring or a major change in strategy or plans. You will not be asked to measure our businesses or results in a different way. You’ll just have to live with outstanding, consistent financial and operating performance measured in the same transparent way we’ve done for the last 20 years.

Once again, we improved our industry-leading safety performance; setting yet another benchmark for the industry. This sort of exceptional operational performance requires consistent execution, and shows the discipline of our organization. Net income was a record $25.3 billion. Return on capital employed was 24 percent, and cash flow from operations and asset sales was more than $43 billion. We invested nearly $15 billion in 2004, and continue to identify and progress world-class profitable investment opportunities. Our financial strength allows us to pursue all opportunities that satisfy our rigorous criteria, while returning increasing levels of cash to our shareholders. In 2004, we returned $15 billion to our shareholders via dividends and share purchases, in excess of dilution.

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So in summary, we had yet another outstanding year. Each of our business lines delivered record results in 2004. The consistency and strength of our industry-leading results is a testament to our disciplined long-term view. We have a broad portfolio of assets that captures the full economic value over market cycles, and takes advantage of diversification across different businesses, economies and regions, and provide more stable cash flow and returns to our shareholders.

Some of our competitors talk about their business in much shorter timeframes than we do. We’ve seen people withdraw from the Asia Pacific region in response to tough conditions, despite the well-known, long-term growth in the region. Some downsized their commitment to refining since they saw no prospects. Most recently, several companies have announced their intention to get out of chemicals, despite consistent strong growth in this segment, and a favorable long-term outlook.

The price people pay for a short-term outlook is missing out on the upside, always adjusting to what just has been rather than what is likely to occur in the long-term. We already produce industry-leading returns across the cycle in all of our business lines. As we review the business line results, we will demonstrate how we are building further competitive advantages.

Underpinning our business is our consistent long-term approach. Discipline and leadership are required to ensure the business is run for the long-term benefit of shareholders. Our approach is built into our core values. This includes a commitment to operate to the highest ethical standards, and is supported by our focus and our systems. All of this is part of the culture at ExxonMobil. You can and many of you have, met Exxon employees anywhere in the world, and they clearly understand our approach, what is expected of them, and the standards we all share. Ultimately, what we are is reflected by our people, and there are none better.

While organizational structures can be copied, I believe the combination of our culture, capabilities and approach is almost impossible to replicate. By now, you should all understand that we deploy our approach as part of a global functional organization. This allows us to leverage the full benefit of our scale, and ensure we prioritize our activities on a global basis. The standardization and consistent application of our processes and systems, is really the precursor to operations excellence which in turn allows us to capture significant cost efficiencies and business improvements.

So why doesn’t everyone adopt this approach? To successfully organize your business functionally on a global scale, you first need to have a number of important elements in place. There is a threshold scale and scope needed to make this significant undertaking worthwhile. You also need to have processes, systems, and information technology infrastructure to coordinate activities on a worldwide basis. Finally, you need a business approach that maximizes the general interest, and integrates across the business functions. All of this is easy to say, but none of this is easy to do.

Another key area that differentiates our approach is commitment to technology. Technology is the lifeblood of our industry. We can hardly take on the world’s toughest energy challenges without our unparalleled suite of proprietary technologies. Many of our competitors have chosen to outsource or scale down their spending on the development of technology. Once again, we would argue that this demonstrates a short-term perspective. We consistently spend more than $600 million a year on research and development. However, as in many things it’s not just what you spend on technology, but how you spend it; where you direct and how you steward your effort. It will come as no surprise that we have spent years and significant effort to understand how to best manage all aspects of technology.

Our process starts with business engagement. Our business lines work with our technology organizations to determine where we are likely to gain the greatest leverage from advancements.

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The result is targeted solutions to the most important business issues and opportunities that will provide a competitive advantage to ExxonMobil. We then deploy those solutions rapidly via our global functional organizations. The advantage derived from the specific technology dissipates over time. Hence the speed of deployment is an essential element of capturing the full value of new technologies. The early engagement of the business lines in our process not only ensures better solutions, but also results in rapid adoption and deployment.

Feeding into this process is an understanding of emerging leads through scientific research. We anticipate the application of new technologies and then identify the likely benefit through a collaborative effort with the business lines. Opportunities are then ranked and evaluated with only the most attractive being pursued, just as we do in any aspect of our business.

The final aspect of our approach that I want to address today is our focus on operational excellence. Consistent application of our operations integrity management system has helped us, once again, set a new benchmark in safety performance. We’ve continued to move towards our goal that nobody gets hurt. I encourage you to look for the correlation between well-run, successful companies, and those who are most competent in safety. If you can get safety right, then you are likely to be very good at managing your operations effectively. Stable, consistent operations also allow more rapid pursuit of improvement initiatives.

Once again, we delivered more than $1 billion in cost efficiencies and we expect to deliver another $1 billion in 2005. Our improvement initiative pipeline remains full, even though we have delivered well in excess of $1 billion in cost efficiencies per year, every year since the merger. There has been a lot of recent talk about industry cost pressures. Cost pressure is not a new thing in our industry, and finding ways of mitigating this pressure has long been a focus of ExxonMobil. We continue to broadly offset the impact of both inflation and new business in our cash operating costs.

Focus and discipline are even more important in these buoyant industry conditions. This is typically when our industry forgets the unforgiving nature of the cycles of our business. We are consistent and relentless in our focus on becoming more efficient. Our productivity continues to improve at an impressive rate. Our workforce now stands at about the same level that heritage Exxon had at the time of the merger with Mobil.

As further demonstration of the efficiency of our business, I point to our industry-leading cash flow generation. We generated more than $43 billion of cash flow from operations and asset sales in 2004. Operating cash flow has averaged more than $27 billion a year in the last five years, while cash uses in 2004 were more than $30 billion. The rapid increase in our cash generation is further demonstration of how we are capturing the upside of the current favorable business conditions. When inevitably you ask me how we manage our cash, I will remind you that we take a long-term perspective. First, we will not do anything stupid or silly. Secondly, don’t expect us to take mechanistic or knee-jerk reactions. We will continue to take a patient, disciplined approach to how we manage cash and our financial position to grow long-term shareholder value.

Our share purchase program is large, and far more consistent than that of our competition. As you can see on the chart, for our competitors, you need to follow the bouncing ball. In 2003, we increased quarterly purchases by $500 million, then increased this by another $1 billion in 2004, bringing the rate of purchases to two-and-a-half billion dollars per quarter, exclusive of anti-dilution. The key here is to focus on the reduction in shares outstanding. Since the merger, we have reduced shares outstanding by eight percent, with shares reduced nearly three percent in 2004 alone. 2004 earnings per share were boosted by 29 cents or about seven-and-a-half percent by the cumulative reduction in shares outstanding since the merger. Our share purchase program is not only more consistent than our competitors’, but has resulted in a far more significant reduction in the shares outstanding, and therefore, better shareholder value.

In the past five years, we have distributed $56 billion to our shareholders. We’ve paid a dividend every year for more than 100 years, and have increased the dividend payment for the last 22 consecutive years. More recently, we have accelerated the pace of those increases, increasing

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the quarterly dividend by around eight percent in the last two years. We will continue to balance distributions of cash to our shareholders through a combination of dividends and share purchases with current and anticipated investment opportunities to create long-term growth in shareholder value.

Our investment program is the outcome of a very disciplined project selection process. Only those projects we are confident will grow shareholder value make the grade. But while we are not opportunity constrained, we are patient, and we are disciplined. It is also important to remember that investment decisions we make today are unlikely to have an impact on our spending profile for several years. The decisions about the money we are spending now were largely made several years ago. You won’t see our investment spending swing with changes in the near-term commodity prices. Once we make a commitment, we deliver on that commitment on time, and on budget. We are also actively pursuing additional opportunities that meet our rigorous criteria, and our financial strength provides a high level of flexibility.

In 2004, we announced several world-class projects, all of which are multi-billion dollar investments. In Qatar, the gas-to-liquids project is a $7 billion, 100 percent working interest project, with start-up expected in 2011. A project of this scale is likely to materially increase our spending, especially towards the end of the decade. Both our Downstream and Chemical business investments have been roughly inline with depreciation in the last couple of years. Looking forward, we have announced several potential projects that are likely to increase the spending profile in these business lines, again towards the end of the decade. Examples include the Fujian refining, chemical and marketing JV in China, and chemical projects in Singapore, Qatar and Venezuela. We have increased the expected capex in our outlook but this is directly associated with new projects, and of course, new business activity. In addition, we will continue to add to our portfolio of investment opportunities, and actual spending in a given year will depend on how many of these projects are progressed.

Every investment decision at ExxonMobil greater than $50 million comes to the management committee, which is sitting with us in the room today. Between us, we have about 180 years of industry experience. We apply our combined business judgment and experience to ensure that we make good decisions for our shareholders. One element of this process is to regularly reappraise all assets in our portfolio, to ensure alignment with strategic objectives, and that they are still generating long-term shareholder value. The results speak to the discipline engendered by this process. In the last five years, we have high-graded our portfolio with more than $6 billion of divestments. The rigorous process we employ to manage divestments delivers true high-grading. The cumulative earnings impact of these divestments is more than $3 billion.

Now let’s look at the alternative approach for stewarding investment capital. Our competitors have consistently written-off substantial portions of their capital employed, whereas our strong asset base has needed minimal write-offs. We’ve shown this chart for a number of years now. This one is just 2000 to 2004. If you add in 1995 to 2000 the numbers are staggering; over $30 billion. I have to stay I am surprised at the apparent lack of focus on the scale of these cumulative write-offs. Over the last 10 years, Chevron has written-off nearly one quarter of their capital employed. Royal Dutch takes second place having written-off over 14 percent, and finally BP has written-off nearly eight percent. Our approach is demonstrated by our consistent results. We believe these results are a direct measure of investment decision quality, implementation and operational excellence.

Return on capital employed is still the best measure of financial performance in an industry as long-term in nature and capital intensive as ours. Beware of people who would seek to promote alternative measures. Despite our competitors’ predilection for writing-off large chunks of their businesses, we consistently out-perform on return on capital employed. Each of our business lines generates industry-leading returns across market cycles. Our approach and long-term perspective deliver superior performance and distinguish ExxonMobil from competition.

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With that understanding of our business at the corporate level, I’ll now hand it over to Rex to take you through each of the business lines. I’ll be making some closing comments before we open the session for questions. Rex.

Rex Tillerson (President):

Thank you, Lee. And good morning everyone. I’ll be reviewing with you each of our business lines, and I believe you’ll recognize the consistency of our approach as I do that across all of the businesses. I’ll highlight our competitive advantages, and how we’re building on and adding to our advantages to further distance ourselves from the competition. Our business plans and strategies, which have been unchanged for some time now, have delivered record results for all of our business lines.

We are on course and well-positioned for continued profitable growth, with many opportunities lying ahead of us. I’ll start first with the Upstream. 2004 was an outstanding year with record earnings of $16.7 billion, up $2.2 billion from 2003. Return on average capital employed was 33 percent. Our production of 4.2 million oil-equivalent barrels per day was the highest among non-government oil companies with production capacity increasing by three percent when you exclude the effects of asset sales and entitlement impacts due to the high prices.

We continue to deliver on our unparalleled portfolio of development projects, with eight major startups in 2004, located in Africa, North America, Europe, and the Middle East. These new eight additions are expected to have an aggregate peak gross production capacity of nearly 700,000 oil-equivalent barrels per day, or a net of over 240,000 oil-equivalent barrels per day. We continue to grow our already industry-leading resource base, adding 2.9 billion oil-equivalent barrels. Proved reserve adds were two billion oil-equivalent barrels, more than replacing production, and resulting in a reserve-replacement ratio of 125 percent. Both of these figures exclude asset sales and the one-day year-end pricing effect or calculation. This marks the 11th year in a row that we have grown our proved reserves.

In summary, an exceptional year. I’ll now provide some further context for those results. An important bottom-line measure of the effectiveness of our Upstream organization is net income per barrel. As you can see, our results far exceed those of competition on a five-year average, and exceed those of most in the single year. On average, for the past five years, we have earned a dollar more on every barrel that we have produced than our nearest competitor. And a $1.25 a barrel more on every barrel we produced than the average of our major competitors.

Four factors contribute to this superior financial performance. Our commitment to technology. We remain committed to the development of proprietary technology and know-how as a cornerstone to delivering results that lead the industry. Second, our disciplined investment approach. We have the patience and discipline to invest selectively only in those projects that deliver the best returns, and only when all of the elements that are required for a successful project are in place.

Third, operational excellence. We are organized to leverage our functional expertise in every project, and delivering operational excellence, reliable operations, and minimizing downtime. And fourth, the relentless pursuit of cost reductions in all aspects of our business. Technology, of course, plays a major role in lowering cost and creating opportunities.

Let me now remind you of the strategies that guide our Upstream business. These strategies have been in place for a number of years. They have served us well and we view them to be appropriate for today’s business environment as well. We pursue all attractive exploration opportunities that meet our criteria in terms of size and quality. We will only invest in and develop those projects that deliver superior returns. We are patient and our ability to balance reward and risk is a key competitive strength. We remain committed to maximizing the profitability of our base assets. And we have positioned ourselves to capitalize on growing natural gas and power markets.

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2004 was another outstanding year for building the future through these additions to the resource base. New field resource additions last year totaled 2.9 billion oil-equivalent barrels, growing our already industry-leading resource base to nearly 73 billion oil-equivalent barrels. Fifty-eight percent of the resource base is liquids. It is geographically diverse, and provides us with a significant presence in the regions of the world with the greatest potential.

Over the last five years, we averaged resource additions of 2.4 billion oil-equivalent barrels each year, at attractive finding costs of 58 cents per barrel. We had our lowest single-year finding cost yet at 44 cents per barrel in 2004.

Resources are added both through drilling, or by-the-bit, and by acquiring rights to already discovered but not yet developed resources. By-the-bit adds in 2004 totaled 1.8 billion oil-equivalent barrels. We participated in 79 exploratory wells with a success rate of 56 percent. The principle adds were from liquids discovered in the deep water of West Africa, gas in the tight reservoirs of the Piceance Basin in Colorado, and oil sands at Kearl in Canada. Adds from already-discovered-but-as-yet-undeveloped fields totaled 1.1 billion oil-equivalent barrels and were primarily from gaining access to additional gas resources in Qatar’s North Field.

These results attest to the effectiveness of our exploration function, and provide a growing foundation for our future reserves and production.

Our exploration effort is designed to identify and pursue all of the attractive opportunities. We already hold exploration rights in more than 30 countries, shown here in green. And we are pursuing many opportunities to acquire new rights. The opportunities range from frontier exploration based on regional basin studies, which identify areas that must be tested, the same approach we took more than a decade ago that led to the discoveries of West Africa.

Using the knowledge, experience and data acquired over many decades, our explorers have evaluated and characterized the potential of every basin in the world. With rigor and selectivity we identify the best opportunities to pursue, and continuously update that selection as new information becomes available. Highlighted on the map are nine areas where we acquired rights in 2004 and early 2005 and include the full range from frontier exploration to additional rights to discovered gas in Qatar.

Securing access to already-discovered resources like those in Qatar often depends on demonstrating to host governments that we can create more total value from the resource than our competitors. Our technical capability and execution excellence are critical to creating that added value, and are recognized by host governments around the world. The opportunity portfolio is large and it’s rich in diversity. We expect it to support continued, significant future additions to the resource base.

Now a lot has been written recently about how the industry is becoming opportunity constrained. We certainly don’t subscribe to that view. Industry has access to a large and diverse array of attractive exploration and resource-capture opportunities, a subset of which are shown on this map. Some are located in countries that are on the path to recognizing the benefit of increased foreign investment. Some of the opportunities are conventional in nature. Other resource opportunities are found by pushing the frontiers of current technology and moving into more remote regions of the world.

These include further exploration in the arctic and in ever deeper waters. They include drilling deeper into higher pressure and higher temperature reservoirs. They include commercializing heavy oil, oil sands, and tight gas. The competition for these resource opportunities is high, and in some cases it’s fierce. Differentiation and success will be determined by technology, project management expertise, know-how, and ability to partner with host governments, all of which play to ExxonMobil’s strengths. Our organization is designed to create greater value both for the shareholder and for the host government, thus helping to ensure access to future opportunities.

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Our continued success in commercializing resources is demonstrated by our consistent performance in adding proved reserves. In 2004, we added two billion oil-equivalent barrels, bringing our total proved reserves to 22.2 billion oil-equivalent barrels. Fifty-six percent of our crude reserves are liquids and approximately 63 percent are categorized as already developed. Our reserves have grown in each of the last 11 years. And over the past five years, our reserve adds have averaged 1.8 billion oil-equivalent barrels.

Our proved reserves are the largest among non-government competitors, and represent approximately 14 years of production at current rates. As the bar on the left shows, the reserves are well distributed around the world, providing the diversity necessary to manage challenges that can affect development and production timing. 2004 marked another milestone in the growth of our successful partnership with Qatar Petroleum with further significant reserve adds from the North Field. ExxonMobil’s commitment of capital to this growing LNG business is a measure of our confidence in the demand for gas, and the liquidity of our targeted gas markets. Proved additions were also made in West Africa, from developments in Nigeria, Equatorial Guinea and Angola, and from new developments and established operations in Europe and the Caspians.

Consistent with the discipline and structure we bring to all aspects of our business, we have long-standing rigorous processes in place that ensure accurate reserves bookings. The process includes review and endorsement of all reserve changes by a central reserves organization comprised of experienced geoscientists and engineers, with final endorsement by the Corporate Management Committee.

The impact of asset sales on reserves in 2004 was just over 200 million oil-equivalent barrels. Our 2004 reserve replacement was 125 percent excluding those asset sales, and was 112 percent including them. This consistent performance is evidence of the depth of our resource base, and our organizational capability to commercialize these resources. While recognizing that about 22 billion barrels of our 73 billion barrel resource base is proved, that leaves us with more than 50 billion barrels of resources already in hand from which to develop new investment opportunities. And of course, we’re not standing still because we’re adding to that every year.

Moving to our second Upstream strategy, we invest only in projects we believe will deliver superior returns. The scale of what we have developed and are now developing is remarkable. Plotted in the upper left is the net cumulative production from the 74 major projects that we have started-up since 1999. By the end of last year, these projects had already produced one-and-a-half billion oil-equivalent barrels, and are expected to have produced more than 3.7 billion oil-equivalent barrels by the end of this decade.

Our investment program is underpinned by a rigorous disciplined project management process and is carefully stewarded. Every project investment is reappraised following start-up on the basis of execution performance, as well as technical and economic results. When we assess the major development projects that have been completed since 1999 and compare the actual cost and schedule with the funding basis, our results are remarkable. The cost, schedule and resources developed have all been delivered within three percent of our investment-decision basis.

On the lower left of the chart is our anticipated share of capex by region for development projects currently in the design and implementation phases. This represents 70 projects with over $50 billion of net investment, targeting more than 12 billion oil-equivalent barrels of net resources and are expected to be brought into production over the next decade.

In addition, there are still 44 projects which are in the planning phase, which are not shown in the totals on this chart. They have not yet reached the design stage. They will develop more than 10 billion oil-equivalent barrels (our share). Our large diverse global portfolio which comes from our 73 billion oil-equivalent barrel resource base allows us to be selective and progress the best projects, consistent with our rigorous and disciplined project management processes. And our global Development Company structure allows us to deploy our resources, our people, and our capital to the right priorities at the right time. The ability to leverage our expertise over such a large range of diverse and capital intensive-projects is a key competitive advantage from the ExxonMobil functional company structure, and the management systems that are in place.

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Because of our participation in a variety of joint ventures, and operated-by-others projects around the world, ExxonMobil does have direct access to data that can be used to benchmark our performance versus that of our competitors in similar projects. I’ve picked a couple of current examples. Let’s look first at development costs in deep-water West Africa. Shown in the upper left chart and measured as gross capex per gross oil-equivalent barrel developed, our performance is best in class. ExxonMobil-operated projects are shown in the red bars. Those operated-by-others are shown in the blue. Our global transfer of technology and our cost and schedule discipline have resulted in unit development costs lower than the competition by up to 20 percent in some cases.

Another example is our success rate in completing open-hole gravel-packed wells, shown in the lower left. It’s one thing to be able to get the well down, but how you finally complete it will determine its ultimate economic contribution over the life of the project. Such completions are critical for production performance and reliability in very expensive highly deviated wellbores such as those that we’re drilling in deep-water West Africa.

We have developed a unique technology for completion from our one-of-a-kind research facilities in Houston and Friendswood. While this is just a couple of examples of a broad range of metrics we track, we are confident that the technology and execution excellence of our functional organization are delivering significant value. Our execution excellence creates greater total value for any given project, which means greater value for a host government, as well as for ExxonMobil’s shareholders. It’s performance like this that contributes to making ExxonMobil the Partner of Choice and is important in our continued access to the best opportunities around the world.

Let me now give you a couple of examples of the excellence of our project execution. Kizomba A in Angola is truly a project delivering superior results. Discovered in 1998 and 1999 on Block 15, more than one billion barrels of gross oil resources are expected to be developed from the Hungo and Chocalho fields that compromise the Kizomba A project. Production started-up in August of last year, only three years following the funding commitment decision.

This represents a record development cycle time for a project of this size, a new benchmark set by Kizomba A. Kizomba A also holds the record for the largest floating production storage and offloading vessel, as shown in the photo, and is the largest deep-water Africa development. Production, which is currently at about 200,000 barrels per day, is ramping up to what is expected to be its peak rate of 250,000 barrels per day later this year. In addition to being on schedule, the project is on budget.

One of the advantages of our large portfolio of projects and our global functional organization is the ability to employ the design one, build multiple approach. The technical understanding from our seismic imaging and our depositional system modeling gives us the confidence in the resource to plan well ahead. We are able to both lower cost and improve cycle time by using the same development design for Kizomba B as for Kizomba A. We expect Kizomba B to start-up later this year with a development cycle time which will improve on Kizomba A’s already record time by five months. Kizomba B is designed to develop a billion barrels of gross oil with a peak rate of 250,000 barrels per day, in this case from the Kissanje and the Dikanza fields.

Kizomba C is expected to develop approximately 650 million oil-equivalent barrels from three separate fields. The project is currently in the designing phase and is progressing towards start-up of the first of the three fields in 2007. Shown in blue on the map are other discoveries in development areas, which are targeted for future development.

Now let’s move to a different type of development in a fundamentally more challenging environment. Our Sakhalin-1 project is one of the largest greenfield foreign investments in Russia, and the execution is on track. Located offshore in the sub-arctic of far northeast Russia,

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the project has the potential to develop more than five billion oil-equivalent barrels from three fields. The full development will require a gross investment of more than $12 billion. The initial investment phase is focused on development of the Chayvo field. Start-up is anticipated in the second half of this year. Oil production is expected to ramp up to 250,000 barrels of oil per day with the start-up of the onshore processing facilities later in 2006. And domestic gas sales are expected to plateau at an annual average rate of 270 million cubic feet per day.

Subsequent Chayvo development phases will be timed to meet export gas sales demand, and to maintain facility capacity. We are exploring options to build a gas pipeline or lines to China and/or Japan for these exports. With exports, Chayvo gas sales could exceed 1 billion cubic feet per day. Subsequent project development phases include the Odoptu and Arkutun Dagi fields to commercialize the full five billion oil-equivalent barrel potential.

Technology enhancements, such as extended-reach drilling, are key to the success of Sakhalin- 1. We are drilling some of the world’s longest reach wells, over six miles to tap offshore reserves from the shoreline. We are also performing complicated completion operations at distances never before attempted. This is a complex project in a difficult physical environment, where we are applying new technology and bringing all of our organizational know-how to bear to achieve exceptional results. We believe that our ability to develop this challenging resource will demonstrate to the Russian Federation the value we bring as an investor in the Russian oil and gas industry.

A key measure of the success of the efficiency with which we develop our resources is the unit development cost. Unit development cost is calculated as gross dollars spent divided by the gross developed barrels, in order to match the full investment dollars with the full reserves being developed. It allows us to compare projects across a full spectrum of operating conditions, resource type, and technology required, independent of the individual fiscal regimes.

Through the period 2001 to 2004, the unit development cost of our portfolio, as shown by the line, is roughly flat at around $3 per oil-equivalent barrel and is projected to remain flat for the next several years. We have maintained this performance throughout a period in which development project capex rose from $2.2 billion in 2001 to nearly $6 billion in 2004. The discipline of our functional organization to deploy the best technology and execution excellence across all of our projects has allowed us to offset external cost pressures. It also is another advantage of having a large inventory from which to choose and having the discipline to select the best of those that are ready.

Our current production of 4.2 million oil-equivalent barrels per day is highly profitable and broadly based with production in 25 countries from nearly 60,000 wells. Our third strategy to maximize the profitability of our existing production is underpinned by our commitment to operational excellence. We maximize reliability and uptime through rigorous maintenance and surveillance programs, and ensure broad dissemination of best practices via our global functional organization.

Approximately 35 percent of our production today comes from the Americas, and about 32 percent from Europe. While this geographic mix will shift over time to the growth regions of the world, production and selective investment in the more mature areas does remain important to continued profitability.

Some of you have cited concerns with rising industry costs, while others point to increasing government take or increased exposure to PSA’s and conclude that companies will fail to capture the value in a strong commodity price environment. Shown here are our quarterly normalized earnings over the last five years. As you can see, the line of best-fit is straight. We are capturing value across the price cycle.

Let’s now look at two examples to illustrate how we maximize the profitability of our existing production. The greater North Sea area continues to be a significant contributor to ExxonMobil, representing just under 30 percent of our production last year. Important to maximizing the profitability is keeping production online, by minimizing downtime.

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The chart shows the progress we’ve made in continuing to reduce the downtime in our operations; this is our operated production, going from 8.2 percent in 2001, to 6.2 percent in 2004. Even in a mature region such as this, the North Sea, we continue to invest selectively in the North Sea to maximize the value. These selective investments include utilizing the existing infrastructure to develop small, but profitable reserves, such as Goldeneye, which we started-up last year to develop 135 million oil-equivalent barrels gross.

Also in 2004, implementation of the Sleipner West project extends the production plateau of 775 million cubic feet per day, maximizing the late-life value of that field. Seven more start-ups of investment opportunities are planned from 2005 to 2007 in both the UK and the Norwegian sectors of the North Sea. Groningen is the largest gas field in Northwest Europe, with a capacity of 11 billion cubic feet per day. A major, multi-year project is underway to renovate production clusters to ensure the long-term integrity of existing facilities, and install new compression to maintain capacity and extend field life.

And finally, we continue to pursue selective frontier exploration as new areas become available. Highlighted is the high risk but high potential acreage we acquired last year in the Norwegian Danish basin. We expect to drill our first well on this new acreage this year.

It is also important to have an ongoing and disciplined rigorous asset management process to maximize shareholder value. We always have assets in the market. We achieve value for lower profitability, limited-potential assets where others are likely to see greater value than we. The level of activity varies from year-to-year as market conditions change, trade opportunities develop, and properties reach maturity. The increased sales of producing properties in 2004 reflect our ability to obtain premium values in the current high-priced environment. Transactions totaling $one-and-a-half billion closed in 2004 as shown here.

The US and Canada transactions are of particular note because of their innovative nature and potential to enhance value. In the Gulf of Mexico and onshore Louisiana, we acquired the rights to jointly explore for deep gas on more than 800,000 acres, where we will have the opportunity to pursue deeper prospects that rely on state-of-the-art technology both in the geologic interpretation and in the drilling capability that others do not possess.

In Western Canada, we farmed out more than 300,000 acres of undeveloped property in mature areas that do not warrant the commitment of our human and capital resources to pursue. We retain a working interest or a royalty of at least 35 percent. Our asset management continues to deliver shareholder value on assets that we have held for some time.

Our fourth strategy is to capitalize on growing natural gas and power markets. Every year, we develop a supply/demand outlook for the worldwide gas industry. And our expectation is that natural gas will remain the fastest growing fossil fuel for decades to come. Our existing gas marketing business and associated infrastructure is already extensive and broadly based. And we expect to substantially expand this business. Colored on the map are countries in which ExxonMobil sells natural gas today.

Also highlighted are our existing LNG projects in Qatar and Arun and our power business in Hong Kong. We have a long and successful history in the LNG business including our activities at Arun in Indonesia which started-up back in 1978. We’re working on new LNG projects in Qatar, Angola, Nigeria, and at the Greater Gorgon-Jansz area in Australia. To support these projects, we are progressing receiving and regasification terminals in the Gulf Coast of the US, the United Kingdom, and Italy. I’ll say more about our growing LNG business in a moment.

Last year, we signed a Heads of Agreement to build the world’s largest GTL plant in Qatar. Our proprietary technology coupled with our strong position in Qatar has created this world-class opportunity to produce more than 1.4 billion cubic feet, and 165,000 barrels of associated condensate and natural gas liquids per day and then transform that gas to high-quality liquid products such as low-sulfur diesel, lube basestocks, and naphtha.

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We also have an important pipeline position in both Europe and the US. Looking to the future, our most significant pipeline projects include those from Alaska and the Mackenzie Delta area of Canada that target the US market. We also anticipate the Sakhalin-1 gas developments targeting markets in Japan and China, as I mentioned previously, and we have a project in the planning stage to bring pipeline gas from Papua New Guinea to Australia.

We have significant holdings in electric power generation, with interest in 13,700 megawatts of generation capacity including 3300 megawatts of cogeneration. In 2004, we celebrated the 40th anniversary of our partnership with China Light and Power in the Hong Kong power business. We have a 60 percent interest in three power stations, totaling almost 6300 megawatts of capacity, with construction in progress to add 625 megawatts of additional gas-fired generation capacity.

Now let’s have a closer look at the North America gas situation. This chart shows the anticipated new supply necessary to meet growing North America gas demand. We know this market well. We sell about three-and-a-half billion cubic feet of gas a day in the US and Canada, meeting more than five percent of the current demand. We are the largest equity holder in North America arctic gas resources both on the North Slope of Alaska, and in the Mackenzie River delta in Canada.

We have patiently held these resources in our inventories since discovery many decades ago, and we are now progressing their development. These projects are enormous and are expected to supply more than 5 billion cubic feet per day of pipeline gas. The fiscal and commercial framework must be durable over the long life of these projects. First gas from the Mackenzie project could arrive as early as the end of the decade, with Alaska gas targeted around the middle of the next decade. We will participate in essentially all of the green arctic wedge which is shown on this chart.

A significant portion of the other new domestic supply shown in red will come from non-conventional opportunities here in North America. We have known for decades that gas is present in sandstone with very low permeability in the Piceance Basin in Colorado. By applying our industry-leading tight-gas well-stimulation technology, we are able to reduce completion cost and increase productivity. A disciplined, step-wise approach is being used to advance the initial development phase. We are also exploring for gas on the deep shelf offshore Louisiana and Texas, taking our technology to new frontiers.

While the resource potential is high, the high temperature and pressures involved make these opportunities very high risk. Nevertheless, solving these sorts of challenges is one of the hallmarks of ExxonMobil.

Turning to LNG, we are well positioned with our partnership with Qatar Petroleum to bring gas to the US Gulf Coast. And we are well advanced in permitting three receiving and regasification terminals there. We anticipate participating in at least two billion cubic feet per day of LNG sales to the US by the end of this decade.

LNG is an exciting growth area of our business. We expect the global market to about double between today and the year 2010. And we are positioned to capture a growing share of that growing market. Today, we participate in projects that compromise approximately 20 percent of the global market, and we anticipate growing that share to about 30 percent of the market by the end of the decade. Our near-term focus is on projects in Qatar.

This chart shows the build-up in gross LNG production from the six new trains expected to come on stream in Qatar from 2005 to 2010. However, we also have rights to other attractive gas resources that can only be commercialized with LNG such as those in West Africa and offshore Australia. Market demand will support development of these resources as well as those in Qatar.

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We anticipate that by 2010, we will participate in two trains that will come on stream from the Greater Gorgon-Jansz area off the northwest coast of Australia, and in one in Angola. We expect start-up in Nigeria to come thereafter.

By the end of the decade, we expect to participate in nearly 80 million tons per year or 10 billion cubic feet per day of LNG projects with a net share more than doubling our current LNG sales to more than two-and-a-half billion cubic feet per day.

LNG is also becoming increasingly important in the European market. We are the largest non-government marketer of equity gas in Europe. We understand that market quite well also. We expect over 50 billion cubic feet per day of new gas supplies will be needed to meet European demand by 2020, and approximately 30 percent of that will come from LNG.

We expect to participate in more than 3.2 billion cubic feet of LNG sales into Europe through our world-scale RasGas and Qatargas projects. The RasGas projects, most notably Trains four and five, anticipate sales of over one billion cubic feet per day into continental Europe via entry points in Italy and Belgium. In Italy, we are moving forward with a fully integrated project to construct the world’s first offshore regasification terminal.

Sales into Belgium will leverage existing and planned third party infrastructure at Zeebrugge. Our Qatargas II project, which we initiated construction on this past month, is designed to deliver over two billion cubic feet per day of LNG into the UK market starting in 2008. In partnership with Qatar Petroleum, we have combined our market understanding, technology and project execution skills with a favorable investment climate in Qatar, and the largest gas field in the world to create the largest LNG project ever undertaken.

We anticipate that we will achieve approximately a 30 percent reduction in total supply chain unit costs when Qatargas II starts up. We are achieving economies of scale, and setting new benchmarks with the largest LNG trains in the industry at 7.8 million tons per year, and the world’s largest ships of 215,000 cubic meters of capacity. Both are about 50 percent larger than those in service today. The pursuit of scale continues as we progress the design of LNG ships of over 250,000 cubic meter capacity, another 15 percent improvement to the large ships we’re currently building.

ExxonMobil also facilitated the largest-ever energy-project financing for Qatargas II at $7.6 billion. It is the first integrated LNG financing from the wellhead to the terminal. Subsequent RasGas projects with sales targeted to the US market will benefit from all of the technology advances and economies of scale developed with Qatargas II. Our unique joint venture business model maximizes the value of LNG to the resource owners by aligning our interests throughout the supply chain and supplies stability over the long-term.

The long-term results expected from the successful execution of our Upstream strategies are shown on this chart. We are working on a large and robust inventory of attractive projects. Our production will be an outcome of these projects. Our decisions will be driven by what is in the long-term best interest of our shareholders by growing value, rather than by growing volume simply for volume’s sake.

The Americas and Europe will continue to be a significant source of volumes as heavy oil, tight gas, and new start-ups replace some of the decline from the maturing base. The Americas and Europe are still expected to provide about 45 percent of our total production at the end of this decade. Russia and the Caspian are forecast to increase sharply from 2005 to 2007 with the start-up of Sakhalin-1 and additional phases at Tengiz in Kazakhstan as well as the Azeri-Chirag-Gunashli development in Azerbaijan.

The majority of the growth across this period though, as you can see, is in Africa and the Middle East. The African growth will be predominantly liquids as additional deepwater projects come online. The Middle Eastern growth is primarily gas from our LNG projects, but I would remind you it includes a significant component of associated liquids as well.

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Over the near-term, growth is driven by new liquid volumes over the next couple of years, whereas towards the end of the decade it will be driven by the gas projects. We should expect year-to-year variation in the growth rate, based on the timing of major project startups, and of course, the level of asset sales and entitlement impacts in periods of high prices will affect year-to-year volume changes. And of course, we don’t operate every project, so we don’t have complete control over the timing of some of the projects that others operate.

When all is said and done though, as you’ve heard us say many times, our success in generating value from the industry’s largest and highest quality asset base is demonstrated by our consistent industry-leading return on capital employed. Our five-year average ROCE is 29 percent versus 26 percent for the closest competitor. And we had the highest ROCE ever in 2004. We will continue to grow our asset base with disciplined and selective investments. The organization and processes we have in place, supported by our industry-leading suite of proprietary technologies will continue to keep us ahead of competition in the years ahead.

Now let’s move to the Downstream. In the Downstream, we also had a record earnings year of $5.7 billion, after adjusting for the Allapattah reserve, generating a record 21 percent return on average capital employed. We captured more of the benefit of the improved market conditions with refinery throughout of 5.7 million barrels per day, our highest ever, excluding the required divestments at the time of our merger with Mobil. We also increased petroleum product sales three percent. These results were underpinned by our continued focus on operating excellence.

We had our safest year ever as we continued industry leadership in safety performance. We had our most reliable year ever, and our best-ever energy efficiency performance. Finally, we delivered over $1 billion in “self-help” in 2004. “Self-help” consists of operating efficiencies and margin enhancement initiatives. These actions are critical to Downstream earnings performance, and are key elements of our Downstream strategies which are outlined in the next slide.

Our approach to the Downstream business is designed to be successful through the ups and downs of a very competitive industry environment. These strategies can be summarized in four broad areas; maximize the advantage of our global scale and integration; create opportunities for margin enhancement and growth; lead the industry in operating cost efficiencies and effectiveness; and maintain capital discipline, selectively investing for resilient, advantaged returns.

I’ll now review how the consistent application of these strategies across our Downstream business has resulted in industry-leading performance.

Looking back to the time of our merger, total Downstream earnings have increased from $1.2 billion in 1999, to a record $5.7 billion in 2004. Downstream margins were poor in 1999, and the higher industry margins last year provided a significant help to our earnings. But many of you have already discovered that this margin improvement alone does not explain our 2004 earnings performance.

In fact, when you look at cost inflation and forex impacts alone, our earnings would have been eroded by almost $2 billion, offsetting a significant portion of the industry margin gain. The more significant element is our ability to deliver on “self-help” improvements, on average nearly $1 billion each year across this period. These “self-help” advantages include things like molecule management, improved reliability, better energy efficiency, growth and conversion capacity, supply chain optimization, work force reductions, Mobil 1 synthetic lube growth and growth in non-fuels income at retail stores, all of which I’ll describe in more detail on subsequent slides.

While margins were strong in 2004, and have been and will continue to be volatile, we continue to believe there is an underlying long-term downward trend rooted in technology advancements and productivity improvements. That reinforces the importance of “self-help”, and in staying above this downward industry trend. The next few slides illustrate how we apply this approach in each of our Downstream segments.

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Starting with Refining and Supply, we continue to capitalize on our global scale and integration across our network of 45 refineries. Our refineries are larger than the industry average, have more conversion capacity than the industry average, and are more integrated with chemical and lube operations than the industry average. We captured over half a billion dollars of additional margin enhancements last year, including initiatives that lowered raw material cost, raised product value, and increased capacity utilization.

I’ll cover a few technology advancements that helped us capture these benefits on a later slide. And we are well positioned in the Asia Pacific to take advantage of its future growth, including the planned, fully-integrated Fujian project in China. We continue to take costs out of our business. Our cash operating costs are the lowest in the industry, due in part to our focus on reliability. We achieved a step-change improvement in reliability this year, with unplanned capacity loss dropping 20 percent versus the prior year.

Finally, we are achieving these results while maintaining capital discipline. ExxonMobil’s project management system continues to provide leading performance in project execution. For example, we started up seven low-sulfur fuel projects in 2004 including four of our proprietary SCANfining units, typically at a four percent lower cost than the industry average according to Independent Project Analysis Inc’s benchmarks. We’ve also further reduced our total inventories by five million barrels in 2004. I’ll illustrate these points in detail on the next few slides.

Our refining assets provide a significant structural advantage compared to Shell, BP and the rest of industry. Our refineries are about 70 percent larger than the industry average, providing us with efficiency advantages. Our refineries have about 35 percent more conversion capacity than the industry average, as a percent of total distillation capacity, providing us with feed flexibility and upgrading advantages. Our refineries are 35 percent more integrated with chemical and lube operations, providing us with upgrading flexibility and efficiency advantages.

The chart on the bottom compares our equity refining capacity with Shell and BP. We have more distillation capacity and conversion capacity than any of our competitors. This conversion capacity includes coking, cat crackers and hydrocracking, allowing us to take advantage of the current wide spread between heavy and light crudes. These structural advantages separate us from others, and are strengths that are difficult for competitors to duplicate. But in addition to these structural advantages, we also utilize these assets better than our competition.

The top chart shows refinery utilization of ExxonMobil against the rest of the industry. We achieved a significant improvement in refinery utilization in 2004. Although 2004 Solomon industry benchmarking data is not yet available, we expect to maintain our leadership and utilization compared to the rest of industry.

In addition to our best-ever reliability, another factor underpinning this performance is our turnaround management. We leverage the very best turnaround practices across our entire refining network. We continue to reduce planned downtime by reducing the time required to complete a turnaround, and extending the intervals between required turnarounds. As a result, in 2004, our record refinery throughput was up four percent versus the prior year.

Another factor improving our utilization is maintenance performance. The chart on the bottom shows that we continue to increase the availability of our equipment while at the same time reducing the costs to achieve these results. Our disciplined Reliability and Maintenance Management system is driving this performance. Since its inception in 1994, we have reduced unit downtime by 40 percent, while also reducing maintenance costs by 30 percent. Equipment Health Monitoring technology is an element of this success. Proactive and preventative equipment monitoring demonstrate the old adage that “an ounce of prevention is worth a pound of cure.”

In addition to better utilizing our assets, we are operating them more efficiently than the competition. The top chart shows cash operating costs for ExxonMobil and the rest of industry. We continued to lower cash operating costs in 2004. When 2004 Solomon data becomes

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available, we expect it will show continued industry-leading performance. In addition to the maintenance cost performance I mentioned earlier, we continue to make significant improvements in energy efficiency and workforce efficiency as shown in the bottom chart.

Energy costs and workforce costs comprise two-thirds of our total refining cash operating costs. In 2004, we had our best-ever energy efficiency year, and our rate of improvement since 2002, I think, you would agree, is dramatic. Our disciplined Global Energy Management System is driving this performance, with more than $1 billion of pre-tax savings identified since its inception in 1999, equal to about 15 to 20 percent of the total energy consumed at our refining and chemical facilities.

Implementation of these steps to date has the added benefit of reducing greenhouse gas emissions by four million tons per year. In fact, these energy conservation steps combined with our cogeneration capacity have the effect of reducing greenhouse gas emissions by over 10 million tons per year, which is equivalent to taking over a million cars off the road every year. Finally, we continue to look for ways to increase our structural advantages through margin enhancements. For example, we continue to grow our conversion capacity.

The chart on the next slide shows the increase in our coking, cat cracking and hydrocracking capacity since 1998. This growth is driven by technology-based process improvements such as the new and improved feed injectors we installed in the cat cracker at Torrance this year and our proprietary coke formation technology which allows us to add up to 20 percent capacity in some of our cokers. Finally, focused investments are also a contributor, like the 40,000 barrel per day delayed coker we added at Baytown in 2001.

We continue to progress our Molecule Management initiatives, capturing $150 million of “self-help” margin enhancements in 2004. And we are on track to capture the $500 million per year prize by 2008 that we spoke about last year. These initiatives involve advancements in molecular fingerprinting and process modeling. This technology enables us to optimize our feedstock selection, including taking advantage of ‘challenged’ lower cost crudes, and maximize the value of each product stream. We deploy this technology through sophisticated computer control applications like the cat cracking tools installed in 2004 at Beaumont, Fawley, Port Jerome and Sakai.

Examples covered in the last few slides illustrate just a few ways our Refining and Supply strategies are demonstrating success and differentiating our performance versus our competitors.

Turning to Fuels Marketing. Our Fuels Marketing business is composed of retail, industrial and wholesale, aviation, and marine fuels, serving customers in over 100 countries around the world. Our marketers work closely with our refining and supply organization to capture the benefits of an integrated supply chain, and ensure our production reaches its highest value outlet.

The retail business is where most of our marketing capital is employed and it remains intensely competitive, with margin erosion of three to four percent per year in real terms. Picking the right locations, and operating them well allows for better margin capture. Our non- fuels income has grown at a pace of about $30 million per year over the past five years, from retail formats such as our award winning On the Run convenience stores.

Our ability to control cost is critical to our competitiveness, particularly with regional and local competition. Since 2000, we have captured $200 million a year in opex efficiencies. For example, we are consolidating our support centers to low-cost areas. The number of regular employees is down 20 percent since 2000.

Finally, we maintain a resilient asset base through a disciplined capital process. Our focused market approach allows us to select and prioritize markets through a comprehensive market planning process. We’ve high-graded our assets, netting a reduction in total retail sites and capital employed of 15 percent since 2000. I’ll illustrate these points in more detail on the next couple of slides.

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We continue to use our scale, global organization and disciplined approach in fuels marketing to improve efficiency. The blue bars on the top of this chart show the nearly $1.2 billion of opex efficiencies captured since 2000. These efficiencies were enabled by our functional organization structure, allowing us to standardize systems and streamline and automate work processes. We’ve also centralized our support activities and consolidated our network of customer service centers from 39 at the start of 2000 to eight by the end of last year. We have reduced retail onsite operating costs, on-airport costs, and site delivery costs. And as you can see by the red line on the top chart, productivity steps such as these have enabled us to reduce regular employees by more than 20 percent since 2000.

Our disciplined capital management approach combines selective investments with ongoing asset high-grading to create a resilient asset base. The chart on the bottom shows our total retail sites and capital employed. We have divested over 7500 under-performing sites since 2000, reducing our total retail chain by 15 percent, and thereby lowering our capital employed. In addition to improving operating cost efficiency, we’ve also made significant improvements in our retail competitiveness.

One of the ways we measure retail competitiveness is with the breakeven fuels margin indicator. This indicator is defined as the unit gross margin required from fuel sales to break even after netting the non-fuels income against the site operating costs. Said another way, lowering costs and increasing non-fuels income drives this number down. The chart on the top shows that we have successfully lowered that breakeven margin by nearly 15 percent for our average US company-operated sites since 2000. And we expect further progress. For example, we recently launched Bengal Traders gourmet coffee in the United States, and have increased our strategic alliances to over 700 sites around the world with partners such as Tim Horton’s in Canada and Tesco in the United Kingdom.

Another measure of retail competitiveness is our market performance. The chart on the bottom illustrates the success of our focused market approach. This disciplined approach involves a rigorous market prioritization and site selection process, including a systematic assessment of the economic and regulatory environment, competitive landscape, supply logistics, and current chain size and performance. This process also involves a detailed market plan which produces a focused customer offering. Combining this approach with disciplined execution results in the success shown in the red bars.

In our focus markets, our market effectiveness, which is a measure of the volume and capital productivity of our retail sites, increased about 20 percent versus pre-conversion performance. Similarly, our sales volume grew 30 percent, and our c-store sales grew 80 percent. These results outperform the industry in these markets, and demonstrate the benefits of our focused market approach. We are in the early years of a long-term program to apply this approach globally. These are just a few examples of how Fuels Marketing strategies are delivering a competitive advantage.

Turning now to our Lubricants and Specialties business. Here once again we capitalize on our global scale and integration. ExxonMobil is the world’s largest supplier of lube basestocks, and a leading marketer of finished lubricants and specialty products. We have twice the basestock capacity of our nearest competitor. In addition, 98 percent of our basestock capacity is integrated with Refining providing efficiency and flexibility. And with strong manufacturing margins this past year, basestocks were a significant earnings contributor. We have three strong global brands, Mobil, Exxon, and Esso, that in 2004 grew faster than the rest of the industry. This growth is driving margin enhancement.

For example, our profitable Mobil 1 synthetic brand grew 13 percent in 2004 and continues to be the world’s leading full synthetic motor oil. In addition, our sales grew 17 percent last year in the fastest emerging markets like China. We also continue to benefit from our strategic global alliances, such as those with Daimler-Chrysler, Caterpillar, Wal-Mart and Toyota.

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At the same time, we continue to drive down cost. Our cost-to-serve the customer, including everything from blending to customer service to the back office support, decreased by five percent in 2004. Our efficient e-based ordering was up by 35 percent last year, and now represents $2.8 billion of revenue. And while we’re growing our business, we’re also maintaining our capital discipline. Our capital employed is down 20 percent since the year 2000, while some of our competitors have increased their capital spending on acquisitions.

As the world’s economies grow, so does the demand for higher quality lubricants. Our business strategy takes advantage of this growth to drive margin enhancement. As you can see from the top chart, Mobil 1 synthetic oil continues to grow faster than industry. We leveraged our leading technology advantage to grow our leadership position in the synthetic market. In the US, we recently announced a new generation of Mobil 1 with an advanced super synthetic system to provide extended performance for 15,000 miles.

Our superior performance is also recognized by the auto industry. Mobil 1 is the endorsed, recommended and/or approved engine oil for more than 50 percent of the new luxury vehicles in the North American market. No other motor oil holds as many engine specification approvals. We’re also capturing growth in emerging markets. The chart at the bottom shows our fast growing lubes sales are up over 50 percent in emerging markets since 2000. China is a big piece of this, and there we are leveraging our strong equipment manufacturing relationships, our well-recognized brands, and efficient supply chain to become the leading international lubes marketer. In fact, China now represents our fourth largest market for finished lubricants.

In addition to growing margins, our business strategy focuses on managing our cost and capital. As I mentioned earlier, our cost to serve customers was down five percent in 2004. This performance is driven by a number of cost efficiency steps. For example, the chart at the top shows we optimized our product offering by reducing the number of our formulations 65 percent since 2000. We also improved our blend plant efficiency reducing the number of blend plants by nearly 25 percent. We leveraged our global scale by sharing best practices to optimize blending and packaging. These are just a few of the steps we’ve taken to lower operating cost.

As you can see from the bottom chart, we’ve also reduced capital employed 20 percent since 2000. In addition to the reduction in the number of blend plants we operate, we also implemented a sophisticated supply chain planning tool that has helped us reduce inventories by more than five percent last year. We reduced our net receivables by focusing on the order-to-cash process to ensure customers get the products on time, invoices are accurate, and the bills are paid promptly. These are just a few examples of how our Lubes and Specialties strategies are growing margins, and differentiating us from our competitors.

In summary, our total Downstream “self-help” efforts are differentiating us from the competition. The chart on the top left shows the results of our capital discipline. We have maintained the level of capital employed in our Downstream business, even allowing for the increased non-discretionary investments required to meet changing fuel specifications and the impact of forex this past year.

We believe flat to declining capital employed or investing at about the depreciation rate is prudent in a modest growth industry with declining long-term margins. In contrast, both Shell and BP have increased their Downstream capital base, largely through new investments, and some acquisitions. The chart on the right shows the results of our margin enhancement and operating efficiency strategies. The bars represent reported earnings. And the red hatch bar shows the impact of the Allapattah reserve item. We are generating higher earnings from a flat capital base. Shell and BP earnings have also risen, but with a much higher capital investment.

The chart on the bottom shows the summary ROCE results. Our Downstream strategies are delivering industry-leading performance for ExxonMobil. These results underscore our belief that success in the Downstream requires sustained commitment to the fundamentals of capital discipline, and continuous improvement in all aspects of our business.

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Now let’s turn to the Chemicals business. Our Chemical business had a tremendous year last year. Earnings of $3.4 billion were the highest ever in our Chemicals business, and the highest ever for any of our traditional petrochemical competitors. The breadth of our portfolio of businesses, our global presence, and our multiple sources of competitive advantage ideally positioned us to capitalize on the improving industry environment. Return on capital employed reached 23 percent, our best result since 1995. It’s significantly higher than any of our competitors. Record sales of 27.8 million tons were up five percent versus 2003. At the same time, Chemical also had a record year in terms of safety, reliability, energy efficiency and production.

Our capital expenditures were $690 million as we continued to selectively invest in high-return efficiency projects, low-cost expansions of our existing asset base, and grow our less cyclical specialties business.

Our industry-leading performance is the result of strategies that position our Chemical business to earn solid returns at the bottom of the cycle, and deliver record earnings at the top of the cycle. We often get asked where we think we are in the Chemical cycle. So before we go further into the strategies, let’s take a moment to review a couple of industry trends.

Where we are in the cycle obviously is really a function of supply and demand. Looking first at industry demand and capacity utilization, we expect demand for petrochemical products to continue to grow faster than GDP as end-use penetration continues to grow. The graph on the left shows in brown the combined demand for three major petrochemical products, polyethylene, polypropylene and paraxylene. Worldwide demand for these products grew six percent in 2004, and is expected to grow about five percent annually between now and the end of the decade.

Shown in blue is the average industry capacity utilization of these same three products. Capacity utilization bottomed out at 82 percent in 2001. Then in 2002, ’03, and ’04 capacity additions of only three percent per year were outpaced by demand growth, which resulted in a significant improvement in capacity utilization. Shown on the right are our long-term margin trends for polyethylene and paraxylene. As you can see, margins started to recover in 2003 and further improved in 2004 supported by the tightening supply/demand balances.

Looking forward a couple of years, indications are that announced capacity additions are moderate. And assuming that demand continues to grow at about five percent per year, one could expect the market to remain relatively tight. Let’s now turn to our strategies.

Our strategies in Chemical have proven sound over time, and they’ve not changed either. They are built around the same set of core competencies as in the other parts of our business. We have a unique portfolio of global businesses, well-positioned to take advantage of synergies with our other operations. Technology is a source of differentiation. We focus on achieving cost leadership and manufacturing excellence. And we are disciplined and selective in our investment choices. The relentless execution of these long-term strategies which I’ll now discuss in detail drives the superior performance you see today.

Our unique mix of businesses has been a key factor in our leading financial performance. We are the world’s largest producer of polyolefins, paraxylene, benzene, butyl rubber, and several other products. In fact, we ranked first or second in over 90 percent of our product lines. As shown on the left graph, we group these businesses in two categories: cyclical and specialties. Earnings from our less cyclical specialty businesses ranging from butyl rubber to plasticizers, are shown in blue. These businesses provide a consistent strong earnings base, and contributed about $700 million last year, up 13 percent from 2003. We continue to selectively invest to grow these businesses. We expect they will continue to provide consistently strong earnings in the future.

The red bar shows earnings from the higher volume, more cyclical businesses. You can see the potential of these businesses. They provide significant earnings in the up cycle. Driven by strong volumes and margins in ethylene, polyethylene, paraxylene and benzene, earnings from these businesses more than tripled in 2004 versus 2003.

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Our expanding global presence, as illustrated on the right graph, is another key contributor to our results. We are ideally positioned and are expanding in the higher growth areas. Our sales in Asia and Africa/Middle East have increased by almost 60 percent since 1998, and now represent more than 30 percent of our total sales.

Sustained superior results require a lot more than strong sales when margins are high. Our pacesetter performance stems from the combination of competitive advantages we have built over time and our relentless effort to further strengthen them. Illustrated here is one of our major advantages, namely Chemical integration with our Upstream and Downstream operations. More than 90 percent of our owned and operated chemical operations are integrated with those other businesses resulting in cost efficiencies, and other synergies, a key one being feedstock advantages.

As shown in the top right graph, we have increased the amount of ethylene we produced from advantaged feedstocks by a third since 2001. And our researchers and engineers continue to find new opportunities to sustain this trend. In 2004 alone, we qualified 59 new feed streams and commercially processed 30 of them. You may remember last year we mentioned that our ethylene feed advantage averaged 15 percent versus gas crackers in the US and naphtha crackers elsewhere. This advantage increased to more than 20 percent in 2004.

Looking at the bottom graph on the right, in Aromatics, the combination of optimization between the refinery and chemical units, reliability improvements and new technologies have produced similar results: a 29 percent increase in paraxylene derived from advantaged feeds since 2001, and again, we expect this trend will continue. And how much is all of this worth? Hundreds of millions of dollars every year generated $1 million at a time from the daily optimization of production plans and feedstocks and the application of proprietary technology.

Technology is a major source of competitive advantage and differentiation for our Chemical business. The combination of our expertise in catalysis, our products and application know-how and process engineering capabilities resulted in three main sources of competitive advantage. The manufacturing processes we used are lower cost. We process low cost feedstocks resulting in lower total manufacturing costs. And we make high value products, generating more margin.

Let’s have a look at some concrete examples.

• Our LRT-2 steam cracking furnace offers a yield and selectivity advantage of up to 10 percent versus conventional technologies, and our high pressure polyethylene process provides a sizeable capital and operating cost advantage. It was recently selected by Huntsman for a new world scale 400,000 ton per year line.

• Our heavy feedstock cracking know-how enables us to convert heavier feeds, and in fact, some crude oils directly into ethylene, while the PXmax process converts toluene into valuable paraxylene with a record yield of more than 90 percent.

• And our Santoprene products and Nexxstar formulations provide our customers with innovative solutions that meet their specific needs, yielding ExxonMobil significantly higher margins than commodity products.

Another key to our success is our ability to reliably supply products in a cost-effective fashion around the globe. It all starts with what we call manufacturing excellence, or our ability to run our plants reliably and efficiently, and to increase capacity of our existing assets cheaply. We use a structured process to identify and rapidly capture process improvements. The graph on the left illustrates the reliability improvements since 2001 measured in millions of tons of capacity. These improvements alone were equivalent to the capacity of a world scale steam cracker, not to mention the associated fixed costs that were also saved.

Supply chain optimization is another source of competitive advantage. We produce our products at advantaged locations such as Singapore, the Middle East, or our large integrated complexes in Europe and North America. We optimize our product flow from multiple supply sources to realize the best possible netbacks for what we sell. And we have a global sales presence and market our products in more than 150 countries. All of this is made possible by our Global Enterprise

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Management System that enables common business practices across our Chemical operations worldwide, and allows us to consistently and effectively meet the needs of our customers, wherever they are.

Building on our competitive advantages, our businesses relentlessly pursue ways to maximize the profitability of our asset base. Similar to what I described for the Downstream, our “self-help” initiatives cover all aspects of what we do, from the products we make and how we make them, to how and to whom we sell them, and how we get them to our customers.

Let me highlight two examples of “self-help”. The first one is the growth of premium products as illustrated on the top graph. Within our commodity and specialty businesses, we have identified products that can be tailored to be meet specific customer needs and consequently generate higher margins. Premium products are typically based upon proprietary technologies and specialized expertise. Examples include metallocene polyolefins, halobutyl and high viscosity polyalfaolefins. Since 2002 we have grown our premium product sales by 13 percent, twice the growth of our base business.

The second example of “self-help” is our relentless focus on cost management. In 2004, our Chemical business generated about $200 million of after-tax cost efficiencies, and reduced unit costs by more than four percent. As illustrated on the bottom chart, workforce productivity improved 15 percent since 2001. This is a constant area of focus. Other areas of focus include energy efficiencies and yield improvements. Overall our “self-help” programs generated more than $600 million of after-tax structural improvements last year.

As already mentioned, demand for our Chemical products is likely to grow at a healthy three to five percent per year. And we are pursuing several avenues to profitably participate in this growth. Thanks to our process technology know-how, we are able to debottleneck our existing sites at significantly less than grassroots costs. As an example, for steam cracking low-cost expansions have generated capacity equivalent to half of a world-scale plant just in the last three years. We’re also supporting the growth of our specialty businesses with new capacity such as the Baton Rouge metallocene elastomers plant, which was started up in January of last year.

And we are progressing major projects located in China, Qatar, Singapore, and Venezuela to provide the Chemical company with the advantaged capacity needed to profitably meet future demand. Some of these projects are still at a very early stage of development, but I’ll quickly walk through them.

Fujian is a fully integrated joint project with the Downstream. It is the only fully integrated project in China with foreign participation. Qatar and Venezuela are ethane-based petrochemical complexes that will include a world-scale cracker and ethylene derivative units. Singapore is a second steam cracking train integrated with the existing complex, and would also include derivative units.

So you can see, we’re well-positioned to continue to grow our business profitably and sustain industry-leading returns, which is a good lead-in to this chart, which provides a comparison of our return on average capital employed to key petroleum competitors, and demonstrates the effectiveness of our business strategies. The top left graph shows that after the major investments we made in the late ‘90s, we have been able to grow our business while keeping our capital employed relatively flat. The earnings graph on the right clearly shows that our strategies are yielding results, while our competitors are struggling to simply generate positive earnings. Focusing on return on capital employed at the bottom, it’s easy to understand why others are withdrawing, while we continue to view Chemicals as a source of earnings growth.

We also do compare our performance with companies outside of the integrated oils, where we compare favorably to prominent chemical companies such as Dow. And we look at performance over the business cycle. Over the past 10 years, we have realized five percent higher return on capital employed than the average of competition. We have a straightforward and resilient business model that differentiates us from all of our competitors. And this is likely to be more and

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more difficult to replicate as the industry environment continues to evolve. Our focus on long-term fundamentals and unwavering commitment to the highest level of performance are hallmarks of our success.

And now as I finish my prepared remarks, let me return to the business model introduced by Lee earlier. I hope what you’ve seen across this discussion of all of our business lines is the consistent, straightforward and transparent approach that generates both industry-leading financial results and sets benchmarks in operating performance. While each of our business lines serves different markets, underpinning them are the core values and commitment to rigorous operating standards, processes, and systems. We conduct our business to the highest ethical standards. How we achieve results is every bit as important as the results themselves. This serves us well in all of our business dealings the world over.

Capital is deployed and stewarded the same way in every business, for growth in long-term shareholder value. Our business priorities are set with a clear understanding of the long-term market trends. We don’t react to short-term variances in the market noise.

And finally, we deploy this approach via our global functional organization gaining maximum benefit from our scale, and allowing us to optimize globally. That concludes my remarks for today, thank you for your attention. And I think Henry is going to give us the rest of the morning’s agenda.

Henry Hubble:

We’ll now take a short break and return at 11 o’clock to hear Lee’s summary remarks, and then take your questions.

BREAK

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Henry Hubble:

Thank you. If everyone could find their seats, please, we’ll get ready to restart. All right, I’ll now turn it back over to Lee Raymond who will have some summary remarks, and then we’ll open it up for Q&As. Thank you.

Lee Raymond (Chairman and CEO):

Let me just try and take a few minutes here, to summarize some of the key points of what we were trying to convey today. As I commented earlier, our industry is driven by long-term trends. Responding to those changes takes discipline and focus. Seeing past the market noise, and understanding the long-term market trends is one of the hallmarks of our approach.

By recognizing the evolving nature of the LNG market, we understood how to unlock the true value of the North Field in partnership with Qatar. I don’t think anyone but ExxonMobil could have put together a project with the scope and scale of what we have done. We went to Qatar with a multi-faceted development plan for the North Field. Look at the breadth and diversity of that expected plan - the world’s largest LNG investment program, gas-to-liquids, pipeline projects, support of local industry and a world-scale ethane cracker. Of course, others had the opportunity before we did in Qatar, but they either lacked the foresight or the capability to develop this world-class resource.

Similarly, by understanding the key levers for long-term success in refining, we have established a portfolio of assets with superior configuration and are well positioned to serve growing demand in Asia. We spent a lot of time, money and focus to build up an outstanding refining business. So it isn’t by chance that we have the right assets with the right configuration in the right place at the right time.

During the downturn in the cycle, we grew our Chemical businesses, increasing our capacity more than 40 percent, and significantly growing our market share, particularly in the most attractive markets. We are capturing far more value than our competition in the improved market conditions. In 2004, our Chemical business generated more than three times the earnings of Royal Dutch. BP booked substantial loss. And we generated 10 times the earnings of Chevron. Our Chemical business does differentiate ExxonMobil.

We start from a very strong competitive position. We already have a global functional organization in place which allows us to better leverage our scale. We have access to an unparalleled existing suite of proprietary technologies. We have an industry-leading geographically diverse resource base of 73 billion oil-equivalent barrels. If the price bulls in this room are right, and $45 oil is here to stay, then we already have an additional 50 billion oil-equivalent barrels of resources that are economic and can be commercialized.

For those who believe there will be some sort of price correction below current levels, then our unmatched financial strength gives us far more opportunity than those who choose to maintain arbitrary gearing levels in the current environment. We already have a high level of integration between our Refining and Chemical manufacturing facilities. You’ve heard today that we ensure that we build on this strength by applying the same integrated model for new facilities in the growth regions of the world. But I also want to draw your attention to the more mature areas of the world, where it is nearly impossible for people to replicate our integrated model, as this would require major investments in markets, but won’t provide an economic return on the investment.

Finally, we have already developed what we believe are industry-leading systems and capability to optimize our global supply. When applied across the scale of our portfolio, this provides a considerable competitive advantage. The market continues to evolve and change, but none of these changes are really unanticipated. We have been working hard to ensure that differentiating capability is ready as opportunities mature. So while we acknowledge the playing field is changing, these changes actually play to our strengths. We are relentless in our focus on improving the business, and this has delivered consistent rapid improvement in all of our business lines.

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Technology increasingly differentiates ExxonMobil. We know we have many existing capabilities that are unique to the industry, and we are already adding to our technology tool-kit. A strong competition for the easy opportunities means they are typically lower return. The projects that are harder to do, whether because of scale, resource complexity or physical environment, are where higher returns are more likely to be captured. The announced withdrawal of competitors from the Chemical business only adds to our advantage. Once they have separated the refining and chemicals business, they have given away any prospect of capturing the full integration advantage. You cannot capture this benefit across a supply agreement. So we expect to grow our advantages across all of our business lines.

Our consistent performance is evident in our industry-leading results across the market cycles. As shareholders, you benefit from our consistent financial and operating performance by the unique combination of high returns with low relative risk. Over a 20-year period, ExxonMobil stock has earned an average of over 16 percent return each year. We accomplished this with far lower risks than our competition and at essentially the same level of volatility as the entire S&P 500 index.

In closing today, I’d like to take another look at long-term value creation. Shown here is a comparison of market capitalization over the past 20 years. Over this period, we’ve seen several price cycles in a wide variety of economic and political conditions. As you can see, the focused pursuit of our long-term strategies has consistently delivered strong value creation. For those of you who are prone to wonder whether ExxonMobil is too big to grow, I point to our growth record, where it really counts in shareholder value. This is probably the best explanation for our large and loyal individual shareholder base. In simple terms, they have been very well rewarded for their loyalty.

As you heard in some detail today, underlying this growth are dramatic improvements in almost every aspect of our business. The capabilities and performance level we have today seemed almost impossible only a few years ago. And have no doubt that we will continue to find the solutions to the world’s toughest energy challenges.

So as I promised in my opening remarks, no radical restructurings. Nor have I asked you to change the way you measure our performance just boringly consistent results. That concludes my prepared remarks. And I’m sure we can find someone up here to respond to any of your questions.

QUESTION AND ANSWER

Question 1

Two questions. First, do the tax changes and other political changes in Russia dampen your enthusiasm for making additional large investments in that country? And then a totally unrelated question, and that is does ExxonMobil see the market involving the volumetric production payments or other ways to capture this frothy price in the futures market, as large enough or of any interest whatsoever in order to try to arbitrage the difference between long-term oil prices outlook and today’s price?

Lee Raymond:

Let me answer the second one first, and the answer is no. That’s not our business. That’s not a game we play. I mean I could get into a long discussion of why we feel that way and feel pretty strongly about that, but it’s probably not a lot of value. I could take up the whole time talking about that. Rex, why don’t you talk about Russia?

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Rex Tillerson (President):

Well the changes that have occurred in Russia over the past year, of course, let me say have no impact on our Sakhalin-1 investment because it being pursuant to a production sharing contract fixes all of the fiscal regime, tax, royalty. It also provides for any disagreements we have to be resolved in international courts outside of Russia. So the stability around that major investment is in place. And the Russian government has reaffirmed their commitment to that both by actions in the Duma and obviously actions as they have worked with us on approving what’s needed to allow that project to go forward.

So we’ll set that one aside because it operates in what I would say is a completely different environment from any other opportunity you might consider in Russia under the existing underground resources laws. Today, the underground resources law is deficient in a number of areas, most notably with regard to security around property rights, obviously stability around the tax structure. And the Russian government and the Duma are taking steps to begin to examine that and there are amendments proposed to the underground resources law. We’ll just see what they do with that.

But I think the broader question around our view on Russia is really one of Russia needing to decide exactly what role it wants foreign investors to take in the development of these natural resources. And I think they are, and have been in somewhat of a period of reexamination around that question. A desire to certainly have a strong control over how their natural resources, most particularly oil and gas are developed because of the importance it plays in their future economic growth and in terms of their geopolitical position in the world as well.

So they – in my view, they have not made it clear to us as a potential investor exactly how they would want us to participate. And certainly under what terms and conditions they would allow us to participate. And until they make that clear to us, and then the legal framework is in place that we feel there’s certainty around that, and stability around it, we’ll just have to continue to watch what is there and what is ongoing.

Because of the big Sakhalin-1 project we have a significant presence on the ground, so we maintain good communications and dialogue with all aspects of the government, as well as good communications and dialogue with Russian domestic companies, and are able to stay very much abreast of how things are progressing there. And we’ll just be patient. And when they’re ready, we’ll see if we’re ready.

Question 2

The cost savings that you mentioned at the beginning of the presentation of around $1 billion and you reiterated that for this year. Subsequently within the presentation, you talked about chemical’s self help of around a billion, sorry 200 million chemicals, one billion in downstream. Could you just talk a bit more about the dynamics of those cost savings? How they have developed by division over the past? And how you see them going forward? And secondly, would further cost savings of that size be contingent on another major acquisition or merger and if you could comment on that?

Lee Raymond:

Well, I think there’s a little bit of apples and oranges there. You have to be careful that you distinguish cost reductions from value enhancements. And I think if you look carefully at the words there, they’re not quite the same words in the Downstream and Chemical.

I think in terms of the cost management, that’s not exclusive to any single activity, by that I mean Upstream, Downstream or Chemicals. Actually, even headquarters gets into that discussion. But, the point is when you add it all up, which we have very carefully, and focus on the cost side of it, not on the value side of it, there was a $1 billion reduction – I’ll come back to that in a broader sense in just a second for – across the whole corporation last year. We expect that there will be another one this year.

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To put that in some context, if you look at Exxon and then ExxonMobil, in essence our operating – cash operating costs today are at the same level as they were 15 years ago. Basically, we have beaten inflation at the same cost level for 15 years. There’s no reason to believe that we can’t continue to find further cost savings.

Question 3

Regarding your long-term return on capital advantage versus the peers, it’s certainly easy for someone like me to see that which comes from avoiding the mistakes which you capture in the cumulative write-offs taken by your competitors. What may be harder for me to understand is whether you also believe or feel you have a return on capital advantage in some of the large upstream projects like Qatar LNG or Qatar GTL, where your competitors are also involved in seemingly similar type projects. Do you believe you have better fiscal terms or operational expertise or technology in some of those big projects? Or is it really just the breadth of the portfolio as well as your being disciplined that accounts for the ROCE advantage?

Lee Raymond:

I think you’re trying to compartmentalize it too much. It’s difficult to know precisely, particularly early on, what the terms are of one arrangement versus another. People don’t publish those. I think it’s clear that if we have similar projects that the execution of the project both in the construction and the operational phase, we do better. I think that’s pretty clear.

And I think that over the life of the project, the cost management, I think, is pretty clear that we are better at that. In many places, as you know, around the world, particularly in the Upstream we have – we’re partners in many projects. And interestingly enough you learn a lot in those ventures. And from that, you can conclude a lot about how you operate versus how others operate. That would be the basis for making that comment.

It’s a little more difficult in the Downstream and Chemicals in the sense that there are really no joint operations. But I think, by all of the indications we have, if you look at things like in Refining, you look at the Solomon surveys, or in the chemicals industry where they do similar kinds of benchmarking, we always come out in the low cost side of the seriatum which means you have an inherent advantage in the facility when it’s constructed. And again, that’s why there’s a lot of attention in our outfit to the continual focus on the management of the cost because after the facility is constructed, even if it has an advantage at the time of construction, you can quickly lose it if you don’t maintain the cost discipline. I think we’ve been able to demonstrate for a long period of time that we can maintain that cost discipline.

I think the point is, I think, over a long period of time generally speaking, I think we have tended to be somewhat more objective in how we’ve evaluated projects, and maybe evaluated the risk- reward ratio somewhat differently than others. And I think, if in our industry when you look at return on capital employed it is a very long-term measure. And so consequently, I think, ultimately what it does is reflect, I’ll call it, a broad approach to the business that is different from company to company, and ultimately that gets reflected in the return.

Question 4

I’ve just got two questions. The first one is really on partnerships and operatorships. It seems that as you’ve become more reliant on others for operatorships in West Africa and the Caspian, that you could potentially be paying for their mistakes, and the fact that you’re not the operator. Just in particular, we’d like to get your comments on Kashagan in the Caspian. Is it becoming less attractive because of the ownership and pipeline issues? Maybe you would comment on the progress you’re making there.

Secondly, just looking at your technology and looking at one of the charts you had on access to oil sands in Canada, just wondering as you have got the capital, the scale, the integration and the technology to really develop these sort of unconventional assets, how do you get access to the resources given that the resources are typically owned by others at the moment?

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Lee Raymond:

Let me – I’ll go to Rex on Kashagan, but in Canada what you just said isn’t accurate as far as we’re concerned. We already have access to the resources in Canada. Others don’t but we have. We have positioned ourselves many, many years ago to have access to those resources.

Do you want to talk about Kazakhstan?

Rex Tillerson:

Well I don’t know if I want to talk about it, but I will.

Lee Raymond:

It was one of us, so I thought…

Rex Tillerson:

Let me first, because you mentioned West Africa as well, let me say first that in West Africa, we have a significant operated position there. We also have, you know, significant holdings in projects that we do not operate. Kashagan is an extraordinarily challenging project just because of its location, the physical environment, the nature of the resource, all kinds of new technology that are going to have to be brought to bear on that. And in dealing with a government that can be challenging at times.

I guess how I would characterize is that I think there is a near uniform recognition among the consortium members that it’s not performing to our expectations in terms of where we find the project progressing today. And there is, I think, a commitment among the group to improve that situation and our expectation is that we will improve it so that project ultimately meets the kind of standards in terms of the investment we’re making that we expect.

Lee Raymond:

See, he was much more circumspect than I would have been.

Question 5

Two questions. I think Rex earlier mentioned, talked about Russia. Can you also comment about Venezuela on change of your view regarding that country’s investment given the recent developments, particularly by them unilaterally changing the royalty rate on one of your projects?

Secondly, if we’re looking at the industry over the past 10 to 20 years, it looks like that an aging trend in the personnel, in particular with the technical part aspect of the personnel, is that a concern for Exxon? Or do you think that you still find as you’re looking at your personnel demographic that you are pretty happy and you don’t see that as a problem? Thank you.

Lee Raymond:

Yes, let me – I’ll take the easy one. I’ll talk about the people, and then Rex can talk about Venezuela. Having worked in Venezuela many years ago, I probably have a bias, so I needed somebody with an objective view.

With regard to the technical skills and hiring technical people, as a matter of fact, frankly our problem over the last few years is that we run the risk of over-hiring. In the sense that when you go out, and as you know, when you go out and interview a lot of people, we’ve always had these formulas that we’ve had about, you know, you have to make X offers to get Y acceptances. Well we found out that Y was a lot higher than we thought it was, and if we weren’t careful we were getting more acceptances than we really had openings. And the quality of the people we are getting is just outstanding, just outstanding.

And of course, we try and recruit not only in this country but around the world, because that’s who we are. So we really have no concern in that regard at all. We do have some concerns about Venezuela. Rex.

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Rex Tillerson:

Well, just as we do in all countries around the world where we have contractual arrangements that prescribe the basis on which we’re going to invest, we’ve made significant commitments to the country on the basis that they’ve made significant commitments to us as to that basis. And I would say by and large around the world governments honor those. They know our expectation and they know that we understand our obligations.

We’ve got a situation in Venezuela where the government has decided they’d like to change the basis on which we made those original investments. We think the contract is quite clear on the question. And so we have, at this point, we’ve just said if you want to change something we’ve got to talk about it. And so we are seeking a dialogue with them to talk about their change, why they think it’s necessary to make it and what can we do to ensure that our value that we originally anticipated with that investment is not eroded. And so that’s the status today.

Now any time a government begins to exhibit characteristics of not wanting to honor contracts, that’s going to cause you a lot of pause with respect to your enthusiasm for putting more money into that particular location. And I think that’s part of the dialogue we want to have with them as well. It’s just, you know, where is this all going. So that’s the status of that situation there. And we hope to get some engagement with them very soon on that question.

Lee Raymond:

I think it also would be fair to say that not every operator has the same contractual arrangements with governments. People need to be careful when they try and draw conclusions for a number of people all at the same time. And the last comment I’ll make is that, as I said, I worked in Venezuela a long time ago, now, 37 years ago or something like that. But I guess my comment would be patience.

Question 6

I wanted to see if we could circle back to your comments on the resource base addition. I appreciated the breakout you gave between the 1.8 billion added by-the-bit and the 1.1 billion from new access to existing resources. I wanted to see if you could give us some comparison for the five-year average in total from the drill bit.

And also, particularly in light of your comments about the resource constraint discussion really being a non-issue, as you look going forward, do you expect to maintain that 1.8 billion per year? And the fact that it could be an upside, what do you expect to see from the drill bit?

Lee Raymond:

Well I think the first comment I’d make is that I don’t think as best as I can remember that last year was an atypical year in terms of the drill bit versus non drill bit. I don’t think there’s anything particularly unusual. The five-year average wouldn’t be significantly different than that.

I think the answer to the second question is, I don’t know if the right word is maintained. I think that we continue to have objectives similar to that for by-the-bit. And obviously if we found opportunities that we thought could improve that, we would do that. And if for some reason we fall short of that on a sustained basis, then we’re going to have to reexamine obviously the whole program. But there’s no particular reason to think that the structure of the program going forward is significantly different than it has been in the past.

Question 7

Two questions if I can. The first one is on the change in the production mix. You’re moving towards longer life projects, a lot of the capital that you’ve been spending over the years is now beginning to deliver. How does that change your view on cash management, the swing between share buybacks and sustainable dividend payouts and so on.

The second question is more conceptual, you talked about access to resource and superior returns in the same breath. Conceptually how does that – how do those two go together. And could you maybe talk a little bit about your view on Libya in that context?

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Lee Raymond:

I’ll handle the first question, and let Rex talk about the second one. The first part of the first question is the same one you ask every year. So I guess I’ll just say we’ll give you the same answer. Why that’s related to the structure of the share buyback program I don’t have the foggiest notion. It seems to me those are rather independent issues. Now if somebody wants to talk about the share buyback program, they should ask about it, and we’ll talk about. Rex, go ahead.

Rex Tillerson:

If I understood your question on the access to resource and how that impacts longer term returns, again, I think the answer really lies in the performance to date in our history and what we’ve demonstrated we are able to do in terms of generating attractive returns in new emerging areas, with new resource acquisitions, with ever-changing fiscal terms. And the terms are always undergoing, you know, when you enter a new area, undergoing discussions.

But the things that we’re able to do, and we’ve talked about them, our strengths in terms of the technology that we bring, the discipline, the project execution capabilities, the cost management, the operational excellence, tend to add the significant value that maintains these returns. So even though other aspects of our access equation may be changing, that performance from all of those things that we talked about which bring added value really lift the value of the whole resource. Our share of that is what allows us to generate – continue to generate the kind of returns in new areas that you’ve seen today and no reason to think we can’t continue to do that.

Libya specifically was an area that we’re interested in. We submitted bids in the recent rounds. Others obviously bid with different economic criteria or a different view of the future than we did. And we’re not going to find ourselves in some kind of a race down to some level of what we would view against our standards and our expectations would be not in our shareholders’ best interest.

Now, as I said, Libya is just getting started. And so, as they’ve said there’s more to come. And I think we have a lot to offer with all of the strengths that I’ve described, and we’ll just see how that plays out. Again, we’re – we have the wherewithal to be patient. We don’t have to be anywhere, any particular place. There’s not a country in the world that we are – we just have to have a presence in. And I think that’s demonstrated by that diversity in the resource base that we showed you, and the broad range of opportunities we have that are really all over the world.

We find that as a real competitive strength that we can take the time and the patience necessary to let these things play out. And when we see the opportunities that are right for us, then we’re able to step in and take advantage of those.

Lee Raymond:

Way in the back.

Question 8

Two questions, if I might. LNG does seem to have pretty strong growth potential going forward. I think you’ve, in a previous presentation, outlined about seven percent annualized demand growth in the coming years. But one of your major competitors is having some problems developing a plant between – or a plant and associated complex between Delaware and New Jersey. Probably some specific things with that are unique. But do you, in a post 9/11 world see any heightened concerns about developing these types of projects around the world, knowing that they’ve always been potentially somewhat dangerous?

Secondly, it seems like the risk premium on oil has had a step change. And though I share your caution about making projections much higher than the normalized level, you know, 70 percent of your proven reserves, and over half of your resource base is now outside of the Americas. Doesn’t that kind of argue for a somewhat higher, if not substantially higher price going forward?

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Lee Raymond:

Well the question of the risk premium is, I think, is pretty difficult to deal with right now when the perception of the world is that the supply and demand is in pretty close balance. I don’t know if you’re seeing really a risk premium in terms of the risk of some kind of terrorist attack. Or on the other hand, you’re seeing people look at it from the standpoint of the scarcity.

The world is kind of in the position now, that if there were a significant shortfall in terms of supply because of some political event, not a terrorist event, the world realizes that a real – a true shortage of crude oil would be a very, very tough issue. And they realize, I think, more people realize, therefore, the value of crude oil in a shortage environment. And until the supply/ demand balance gets a little more flexibility in it, I would say, we are in the mode where the fundamentals of supply and demand really don’t drive the price.

People ask me today to do a price forecast, and my comment is well first let’s do a political forecast. You give me the political forecast, and then we’ll work on – you need to tell me what do you think is going to happen in Venezuela, Saudi Arabia, Nigeria, Iraq, Iran, Indonesia, Russia. And once you can clarify exactly what’s going to happen in all of those places, we can talk about the price of oil.

I run little risk of ever having to do that, because nobody can ever do the political forecast. Nobody can ever do the political forecast, so that way you kind of avoid the problem but you really don’t in the sense that that’s – that’s the world we’re in.

Now we’ve been here before. And what happened was eventually the system, my words, the system imploded. There was an economic downturn in the world. A lot of build-up of supply in the sense of projects were in the pipeline. And once they start, they will continue to come online whether the price of crude is up or down. And that’s what happened in the early ‘80s, and that’s what lead to the collapse, literally the collapse in December of 1985. And we went through it for a long period.

I mean we had prices that were high even by today’s standards in the early 1980’s that ran for about four-and-a-half years. And most of you probably aren’t old enough to remember it, but there were people who said the price was going to go to $100 a barrel in dollars of that day. And the prices then were $32 which is, in prices of today, is well above the current price. Then came December 1985, the prices went to $10. They went from $25 to $10 in two weeks.

Some of us can very painfully remember that happening. I’m not going to say it’s going to happen again. Who knows what the circumstances are going to be. But I think the comment I would make is oil is a commodity. It’s hard to identify any single commodity that has ever maintained a very high price over a very long period of time. That’s not the way the commodities work. Next.

Question 9

Two questions if I may. I’m just wondering if you could discuss the potential for power investments going forward. And how you assess each project, and like the $27 oil project metrics for investments there. And then, I was wondering if you could just briefly discuss FX going forward and Exxon’s policy.

Lee Raymond:

By power projects, do you mean, what do you mean?

(Question 9 cont.):

Generation, merchant generation?

- 30 -

Lee Raymond:

Well we’re not really in that business.

(Question 9 cont.):

OK. Well then, FX …

Lee Raymond:

I mean we are in Hong Kong. And Hong Kong is a small part of the world in that sense.

(Question 9 cont.):

Right.

Lee Raymond:

And, you know, what we do in Hong Kong is driven by Hong Kong demand and with China Light. It doesn’t really have, frankly, have a lot to do with what the price of either gas or coal is in to the power plant. The question is we’ve got an obligation to meet the power demand and we’re going to meet the power demand. Now are you talking about cogeneration projects in refineries?

(Question 9 cont.):

Right.

Lee Raymond:

Ed, do you want to comment about that?

Ed Galante (Senior Vice President):

As we pointed out earlier, we’ve made a lot of investment in cogeneration facilities. The motivation there is the combined generation of steam to run our operations, which are huge energy consumers, heat consumers. And we typically size cogen facilities to meet that heat sink. In some cases, that will produce power that’s in excess of our own electric power demands, and then we sell into the grid when that happens.

In each case, obviously it depends on the regulatory environment. For example, right now, we’ve got a couple of projects going in Texas, very conducive because they’ve deregulated the power grid. California a different situation, we can’t justify building cogen there. So it really depends on the regulatory regime in each area, the size of our heat sink, as to how much we make. And then the electricity that’s produced falls out of that, if it’s marginal to our needs, we sell it into the grid.

Lee Raymond:

But the economics are really driven by the management of our own heat sinks.

Question 10

I wonder if I could ask a question about the UK gas market. You’re obviously going to deliver a large proportion of the LNG into that market from 2008 onwards. Do you see summer prices equalizing to the winter prices? Or do you see increased storage being added to the UK gas market going forward? Also, how do you see your LNG with respect to Ormen Lange and other infrastructure-led options coming in from the continent into that market with respect to costs?

Lee Raymond:

Well I think the first point is, of course, you can’t view the UK market in isolation. You have to view it in the context of the continent the inter connectors there. And there’s another line going to be built by Gasunie so there will be two large lines that go from the continent to the UK, which will tend to, I think to probably some degree levelize the seasonality. But the facts, I think, are always going to be there that the UK with its rapidly declining resource base is going to be strongly dependent on imports. And therefore, there is likely to continue to be strong seasonal swings.

If somebody has the notion that seasonality is going to go out of the gas market, all they have to do is look at the United States to figure out that that’s not going to happen. And if somebody in the UK has the view that they have as an objective that they’re going to eliminate seasonality, they’re going to have to talk to somebody a lot higher than any of us to deal with that issue.

- 31 -

Question 11

Thanks, Lee. I have two questions, somewhat related. You have consistently emphasized return at the expense of growth. And I guess I’m a little bit curious as to what it is that’s convinced you that long-term shareholder value is best served by establishing the trade-off that you appear to have.

Second, as I say, a related question. One of the advantages that ExxonMobil clearly has that I don’t think merited mention this morning was perhaps the lowest cost of capital in the industry. Low cost of capital would seem to give you an advantage position, relative to the capture of incremental discovered resource opportunities.

Yet, over the last I don’t know, a couple of years maybe, I sense that the company’s attitude towards host country governments if anything has gotten a little bit more confrontational. One of the examples was actually brought up this morning. How do you reconcile the capability to use that low cost of capital to your advantage, and an attitude or relationship with some of the key host country governments that seem to be going in a bit more confrontational direction.

Lee Raymond:

Well let me deal with the first one first, and that is in your terms return versus growth, and I think by growth you mean volume. (No.) Well then I don’t think the trade off is as your describe, hence let’s take business by business. Clearly in chemicals, we’ve had significant growth by any measure.

In the downstream, the areas of the world where that is relevant, we’ve had growth, however you want to look at that. In the areas where there is not volume growth, I would come back to the point that I think we’ve made for many, many years, the idea is growth in profitability and growth in efficiency because ultimately that’s what drives the return, and the return drives the return on capital employed.

In terms of the question of a low cost of capital and how that relates to your theory that we have become more confrontational, I don’t see the relation of that one to the other at all. And as a matter of fact, I don’t really necessarily believe that we have become more confrontational. The fact that we as a company continue to still believe in the rule of law, in the sanctity of contracts, is not something that we will quickly abandon. And if that turns out to lead to periodic discomforts in certain parts of the world, if we’re going to continue to invest billions and billions of dollars, we think we need to continue to have a belief in the sanctity of contracts and the rule of law, and we’re not going to change our view on that subject either.

Question 12

Can I just clarify something from earlier, did you suggest that the second half of this decade, you’d be spending a bit more in the downstream than in the first half or did I mishear that? Is it just a different type of investment that we should expect towards the end of the decade? That’s the first question.

Lee Raymond:

You mean in refining and marketing?

(Question 12 cont.):

And chemicals.

Lee Raymond:

I’ll let ((inaudible)). Chemicals is not the Downstream, but …

- 32 -

(Question 12 cont.):

Let’s say refining, marketing and chemicals. And the second related question is, there’s a lot of talk about how the United States in particular is entering a period of capacity constraints in refining either at the front end or in the middle of refineries. Does Exxon believe that and if so do you expect to do anything about it in terms of capital?

Lee Raymond:

Steve, why don’t you comment about Chemical’s capital and then Ed can take the rest of that.

Steve Simon (Senior Vice President):

Well in the Chemicals business, as was mentioned, currently we are exploring and studying various opportunities in terms of meeting the growth potential, particularly in Asia and also in South America. Those would include the project that was mentioned at Fujian, our parallel train at Singapore, our world-scale ethane crackers at Qatar and Venezuela. And I would also point out that some of those are in very, very early stages of study. And we’ve not taken decisions on any of those at this point in time. So whether or not those materialize, we’ll see.

We’re in a growth business, growth industry. It was mentioned five percent per year on average. Now the commodity products are up in the five, six, or even higher percentage. So when you look at meeting that growth potential and doing so profitably, and obviously we’re not going to invest in any of these unless we can do so in an advantaged fashion, advantage in terms of feedstock, world-class in terms of efficiency and capability. Also, the integration advantage that we talked about earlier between the Upstream and the Downstream. Assuming that we can do so and do so profitably, then yes, that could end up with some higher levels of expenditure than what we’ve seen over the last couple of years. Although, if you go back further in time, again, we had some major expenditures as well.

So over the last couple of years, yes, we’ve been investing in efficiency type projects, no major investments. What we’re looking at doing later on if all – if some of these materialize would be no different than what we’ve done in the past. That is, how do we continue to position ourselves to grow profitably in this growth business.

Ed Galante:

With regard to the Downstream capital question, our basic – three quarters of our Downstream investment activity is in what I would call the mature parts of the world, Japan, North America, Western Europe. And in those areas, Japan, for example, you’ve got zero to declining growth. North America a percent to two percent. In Western Europe, zero to one percent long- term growth. We don’t see ourselves investing there much beyond depreciation. And within that, there’s a mix of activities in terms of regulatory requirements, margin improvement steps, efficiency activity that make up that base.

On top of that, though, you have a separate look at parts of the world like China where we talked about the Fujian integrated project, assuming that continues to proceed. Those additional investments will be kind of above and beyond the depreciation investment in other parts of the world. Now with regard to refining capacity, globally if you look at the supply and demand for refining capacity, refining capacity clearly exceeds demand. So we don’t see a shortage of refining capacity around the globe.

When people tend to talk about refining capacity, they tend to come home here to the US, and talk about refining capacity here. And I think I’d start that discussion by saying the US has been a marginal importer of refined products for decades. So clearly, over the past several decades, some smaller sub-economic marginal refining capacity has shut down. And clearly today refining capacity is being more heavily utilized than in the past and is closer to the supply/demand balance.

We see that going forward that that will continue to grow, and will continue to be crept up incrementally at the rate of one to two percent. And that’s about the same rate that we see

- 33 -

demand growing. So longer term, you’ll see a lot more volatility because the supply/demand balances are tighter. And if you have a bit of a spurt in demand one year, and you have a fall off in demand the following year either because of economic activity or weather or whatever causes it, you may see sudden tightness or a sudden looseness in the market.

But we don’t – our long term view upon which we make our investment decisions is that we will continue to see an underlying long term downward trend in refining margins driven by technology advancements, and productivity improvements.

Question 13

First, can you comment on your recent sale of Sinopec shares that you held, and the rationale behind that? And secondly, you said that if someone asked about buyback, you’d talk about it, this is a question about buyback.

Lee Raymond:

I knew eventually somebody would do that. Sinopec, yes I think some people, at least from what I’ve heard, some people have misunderstood what that’s all about. I think you need to go back and understand how we got the Sinopec shares to begin with, what the whole point of the exercise was. Sinopec was trying to go into the public markets and concluded that it would be helpful for them if some of the majors, and I don’t know the conversations with others but the conversation they had with us was that it would be helpful if the world would see us as holders of some of their shares, and therefore supportive of their entry into the public markets.

That is not something we would normally do. We generally do not like to hold small shares in anything. And I guess, I’d say in anything. And particularly, we do not normally invest in shares of other companies. But given the long term relationship we had with them starting way back in the exploration – in the area of exploration and then the projects that we were working on with them, we concluded that we would do that. But there was an understanding at the time that that was a – that those were shares and after some period of time, we would have the right to sell those shares if we wanted to sell them. And it’s no reflection on Sinopec.

It’s no reflection on the management. It’s no reflection on the joint ventures we have with them. We’re not trying to make a statement of any kind. It just comes back to the point we made early on that this is not normally something we do, and we don’t normally hold shares of other companies. And therefore, we concluded when we looked at the market price, that it was an attractive time to sell. And frankly, to unburden the shares, and unburden Sinopec from having us as a major shareholder. And that’s exactly how it should be looked at.

Nobody should try and read anything else into it. The Sinopec management knew there was a time when we were going to sell the shares. We obviously couldn’t tell them right ahead of time for obvious reasons. But as soon as we made the decision to do that, we told them we were doing it. There’s no mystery about it.

In terms of the share buyback, I know there’s a lot of discussion about that. I think we should take a minute or two to kind of understand where we come from on all of this, and what our view of the role of buybacks is.

We really got into the share buyback business in the early 1980’s, the last time when there was a sustained high price of crude oil for four or five years. And we concluded at that time, when we looked at the alternatives, that the best thing to do with the money was to buy back shares. The alternatives were at that time to go out and buy some other companies. But we didn’t think that was the right thing to do at the time, because we didn’t believe the price structure was stable. And for many of those people who went out and bought companies in the early 1980’s, they ended up with a lousy return if any return at all.

Now I will also say to you that all of you, not you personally, but of the group of you, in the early 1980’s when we announced the share buyback program, there was not one analyst that supported it. Not one. We came under enormous criticism for lack of foresight. There were no growth opportunities. We had the wrong balance between return and growth. It’s almost like somebody read those things from 25 years ago before they came to the meeting today.

- 34 -

But we persisted, because our view was that this was a very long-term business. Things play out over a very, very long period of time. We continued share buybacks all through the ‘80s, up and down depending on what the results were, and what the cash position of the company was. And we did it, actually right up to the merger. Now, to put this in perspective, by the time of the merger, starting from 1983 we had purchased over a billion shares of Exxon stock at a cost of $16 billion. That billion shares bought Mobil for $80 billion. A pretty good investment for the shareholders.

So I guess my comment to you would be, you have to have a very long perspective. There are lots of ways to deal with it. The opportunities will come for the people who have the strength and the financial flexibility. In terms of the near term, I think you can expect that we’re going to continue to buy shares back. And if crude prices remain high, as they have now for a while, we’ll probably have to look at the rate at which we buy them back. But you can be sure that ultimately, the objective is shareholder value, and to return the money to the shareholders. Maybe we ought to stop, Henry.

Henry Hubble:

A good place to stop. That concludes the analyst meeting for this year.

END

- 35 -

EX-99.2

Exhibit 99.2

1

Taking on the world’s toughest energy challenges. TM

Analyst Meeting

New York March 9, 2005

2

Cautionary Statement

Forward-Looking Statements. Outlooks, projections, estimates, targets, and business plans in this presentation are forward-looking statements. Actual future results, including demand growth and supply mix; ExxonMobil’s own production growth and mix; resource recoveries; project plans, timing, costs, and capacities; capital expenditures; revenue enhancements and cost efficiencies; industry margins; 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 item 1 of our most recent Form 10-K and on our website at www.exxonmobil.com.

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, and other terms used in this presentation, including information required by SEC Regulation G, see the “Frequently Used Terms” posted on our website. The Financial and Operating Review on our website also shows ExxonMobil’s net interest in specific projects.

3

2004—Record Results

Record safety performance

Record financial performance

– Net Income $25.3 B

– ROCE 23.8 %

– Cash flow from Operations

and Asset Sales $43.3 B

Cash Returned to

Shareholders $14.9 B

Capex $14.9 B

4

2004—Record Results

Earnings $B

30 25 20 15 10 5 0

‘00 ‘01 ‘02 ‘03 ‘04

Chemical Downstream Upstream Net Income

Record results in all business lines

Industry-leading results across the cycle

Building competitive advantage

5

Consistent Long-Term Approach

Leadership, discipline, and long-term perspective

Core values established in our culture

Commitment to highest ethical standards

Transparent and straightforward

Not easily duplicated

Disciplined Investment

Operational Excellence

Growth in Shareholder Value

Industry Leading Returns

Superior Cash Flow

6

Global Functional Organization

Exxon Mobil Corporation

Upstream

Development

Exploration

Gas & Power Marketing

Production

Upstream Research Company

Downstream

Fuels Marketing

Lubricants & Specialties

Refining & Supply

Downstream Research & Engineering Company

Chemical

Basic Chemicals and Intermediates

Manufacturing

Polymers

Chemical Research & Engineering Company

Corporate Research Global Services Organization

7

Capitalizing on Technology

Expenditures* $M

700 600 500 400 300 200 100 0

XOM

RDS

BP

CVX

XOM

‘99-’03 Avg ‘04

* Based on SEC definition

Business Engagement

Global Implementation

Competitive Advantage

Focused R&D

Differentiated Solutions

Identification of Promising Emerging Technology

Scientific Research

8

Safety Leadership—‘Nobody Gets Hurt’

Safety—Lost Time Incident Rate

(Incidents per 200k hours)

0.5 0.4 0.3 0.2 0.1 0.0

‘00 ‘01 ‘02 ‘03 ‘04

U. S. Petroleum Industry Benchmark

Employee Contractor

9

Cost Control and Productivity

Cash Operating Costs $B

40 30 20 10 0

CPI

‘00 ‘01 ‘02 ‘03 04

Cash Operating Costs at 2004 Forex & Energy price *

Workforce

‘000s

105 95 85 75 65

‘00 ‘01 ‘02 ‘03 ‘04

More than $1B in cost efficiencies in 2004

Another $1B expected in 2005

Offsetting inflation and new business costs

Significant productivity improvements

* Operating Costs (see Frequently Used Terms) excluding depreciation and depletion

10

Industry-Leading Cash Flow Generation

Annual Cash Flow $B

50

40

30

20

10

0

‘00 ‘01 ‘02 ‘03 ‘04

Asset Sales Operating Cash

Capturing the upside

Average operating cash flow of more than $27B over past five years

Long-term approach appropriate in cyclical business

11

Superior Shareholder Distributions

Share Purchases* $B

2.5 2.0 1.5 1.0 0.5 0.0

1Q 2Q 3Q 4Q1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q

‘01 ‘02 ‘03 ‘04

XOM RDS BP CVX

* In excess of dilution

Shares Outstanding*

%

100 98 96 94 92

‘00 ‘01 ‘02 ‘03 ‘04

CVX BP RDS XOM

* Average annual fully-diluted shares calculated based upon publicly available data

12

Superior Shareholder Distributions

Cumulative Distributions $B

60 50 40 30 20 10 0

‘00 ‘01 ‘02 ‘03 ‘04

Share Purchases*

Dividends

* In excess of dilution

Distributed $56 billion in last 5 years

Paid dividends for more than 100 years

Increased the dividend every year for the last 22 years

Balance distributions with creating long-term shareholder value

13

Investing in Profitable Opportunities

Capex by Business Line $B

20 15 10 5 0

‘00 ‘01 ‘02 ‘03 ‘04 ‘05 ‘06

Estimate

Chemical / Other Downstream Upstream Planning Range (Total) $B

20 15 10 5 0

‘07-’10 Average

Growing GTL Investments

Estimate

14

Capital Stewardship

5-Year Cumulative Divestments* $B

7 6 5 4 3 2 1 0

‘00 ‘01 ‘02 ‘03 ‘04

Chemical

Downstream

Upstream

Coal & Minerals

* Net book value of asset sales excluding mandated divestments

Rigorous management process

Maximum shareholder value

Cash flow totals $9.2 billion

Positive earnings impact of CVX $3.4 billion

15

Capital Discipline

5-Year Cumulative Write-Offs* $B

20 15 10 5 0

Cumulative ExxonMobil write-offs

BP RDS CVX

‘00 ‘01 ‘02 ‘03 ‘04

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

ExxonMobil’s strong asset base

Large portions of competitor capital employed written-off

Measure of quality of investment decisions

16

Sustained Competitive Advantage

5-Year Cumulative Write-Offs* $B

20 15 10 5 0

‘00 ‘01 ‘02 ‘03 ‘04

Cumulative ExxonMobil write-offs

BP RDS CVX

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

5-Year Rolling Average ROCE*

%

20 18 16 14 12 10 8 6

ExxonMobil

RDS

BP

CVX

‘00 ‘01 ‘02 ‘03 ‘04

*Calculated on a consistent basis with ExxonMobil, based on public information. Competitor information estimated for 2004.

17

Upstream

2004 Highlights

Record Earnings $16.7 B

ROCE 33 %

Production Volumes 4.2 MOEBD

Major Project Start-ups 8

Resource Adds 2.9 BOEB

Proved Reserve Adds (1) 2.0 BOEB

Reserve Replacement (1) 125 %

(1) Excluding single-day, year-end pricing and asset sales

18

Upstream

Record Results

2000-04 Net Income per Barrel* $/OEB

12.0

10.0

8.0 6.0 4.0

XOM RDS BP CVX TOT

* Calculated on a consistent basis using public information

2004

CVX excluding gains on asset sales

Commitment to Technology Investment Selectivity Execution Excellence Cost Efficiency

19

Upstream

Upstream Strategies

Identify and pursue all attractive exploration opportunities Invest in projects that deliver superior returns Maximize profitability of existing oil and gas production Capitalize on growing natural gas and power markets

20

Upstream

Growing Resource Base

Total Resource Base 73 BOEB

80 40 0

YE ‘04

Asia Pacific

Middle East Caspian Africa

Europe

Americas

‘00-‘04

‘04 Avg

Resource Additions

(BOEB) 2.9 2.4

Finding Costs

($/OEB) 0.44 0.58

Continued focus on high

potential areas

21

Upstream

Pursuing and Securing Resources

Norway

Canada

Qatar

Madagascar

Congo

Brazil

Colombia

Gulf of Mexico

Nigeria/Sao Tomé Principé

Countries with Exploration Acreage

2004/2005 Captures:

Frontier Exploration Established Exploration Discovered Undeveloped

22

Upstream

Diverse Industry Resource Opportunities

Conventional Arctic Deepwater

High Pressure/High Temperature Heavy Oil, Oil Sands, and Tight Gas

23

Upstream

Proved Reserves Continue to Grow

Proved Reserves by Region

BOEB

25 20 15 10 5 0

YE ‘04

Asia Pacific Middle East Caspian Africa

Europe

Americas

‘00-‘04 ‘04 Avg

Reserve Additions

(BOEB)* 2.0 1.8

Reserve Replacement

(%)* 125 115

* Excluding single-day, year-end pricing and asset sales

24

Upstream

Global Development Portfolio

Cumulative Volumes Contribution from ‘99-‘04 Major Start-ups

BOEB (Net)

4 3 2 1 0

‘99 ‘00 ‘01 ‘02 ‘03 ‘04 ‘05 ‘06 ‘07 ‘08 ‘09 ‘10

Net Project Capex $B

15 10 5 0

Americas

Africa

Middle East

Russia/Caspian

Europe/Asia Pacific

Current Projects in Designing and Implementing Phases

74 major project start-ups since 1999

8 in 2004

Consistent, rigorous project management

Unparalleled portfolio

Investing more than $50B

25

Upstream

Execution Excellence: Deepwater West Africa

Development Cost

Gross $/OEB

9 6 3 0

Angola Nigeria

ExxonMobil Operated Operated by Others

Well Completion Success

% Success

100 50 0

West Africa

Creating greater value

Applying best technology

Utilizing global functional capability

26

Upstream

Execution Excellence: Angola

Producing Developing

Future Developments

Xikomba

Kizomba C

Kizomba B

Kizomba A

Kizomba

Kizomba ‘A’ sets record for fastest cycle time and largest FPSO

Kizomba ‘B’ start-up in 2005, 5 months faster than ‘A’

Kizomba ‘C’ progressing towards 2007 start-up

Benefiting from sub-surface technology and Design One—Build Multiple approach

27

Upstream

Execution Excellence: Russia

Mongolia

Sakhalin—1

Chayvo start-up in 2005 Arctic expertise World-class horizontal wells

Increase gas sales to 1 BCFD with export

Develop Odoptu and Arkutun-Dagi Fields

Odoptu Chayvo and Arkutun-Dagi Fields

Oil Pipeline

Under Construction

Gas Pipelines

Existing Under Construction

Seoul

Tokyo

Sapporo

China

Harbin

Russia

Khabarovsk

DeKastri Oil Export Terminal

Japan

Basin

28

Upstream

Developing New Resources

Unit Cost $/OEB

Annual Project Capex $B (Net)

Unit Development Cost*

4 3 2 1 0

‘01 ‘02 ‘03 ‘04 ‘05 ‘06

6 4 2 0

*Gross, full portfolio

Commitment to technology Global functional organization Broad, diverse portfolio Execution excellence

29

Upstream

Maximize Profitability of Existing Production

2004 Production by Region kOEBD

5000 4000 3000 2000 1000 0

2004

Caspian Middle East Africa Asia Pacific

Europe

Americas

Countries with

Existing XOM Production

30

Upstream

Maximize Profitability from Existing Production

Capturing Value Across the Cycle

Normalized Earnings (2000-2004) $/BBL

14 12 10 8 6 4 2 0

10 20 30 40 50

R2 = 0.96

Production-Weighted Marker Price ($)

2004 Production by Region kOEBD

5000 4000 3000 2000 1000 0

Caspian Middle East Africa Asia Pacific

Europe

Americas

2004

31

Upstream

Maximize Profitability: North Sea/Europe

Downtime*

%

10 8 6 4 2 0

‘01 ‘02 ‘03 ‘04

Leveraging infrastructure to develop additional reserves

Maximizing late-life field value

Selective development and exploration

* Operated Liquids

North Sea

Njord

Kristin

Ormen Lange

Statfjord Late Life

Fram East

Sleipner West

Norwegian/ Danish Basin

NORWAY

SWEDEN

Goldeneye

Scoter

Arthur

Caravel

DENMARK

Groningen Upgrade

GERMANY

NETHERLANDS

ENGLAND

NORTHERN

IRELAND

IRELAND

2004 Start-ups 2005—2007 Start-ups 2004 Exploration capture

32

Upstream

Maximize Profitability: Asset Management

Major 2004 Divestments and Trades

Western Canada

Rockies

West Texas

Gulf of Mexico

Delhi

Divestments & Trades*

$B/Yr

1.5 1.0 0.5 0.0

‘00 ‘01 ‘02 ‘03 ‘04

Production kOEBD 1 10 5 10 55

Rigorous, disciplined process

Achieve value for lower profitability, limited potential assets Utilize non-strategic assets to achieve strategic value

* Producing properties; sales value

33

Upstream

Growing Gas and Power Opportunities

Alaska

Mackenzie

North Sea

Qatar

Nigeria

Angola

Sakhalin-1 -

Hong Kong

Arun

PNG

Greater Gorgon / Jansz

XOM-Existing LNG LNG Opportunities

Pipeline-Gas Opportunities Power Opportunities

Gas-to-Liquids

XOM Active Terminal Development Countries with XOM Market Presence

34

Upstream

Well-Positioned: United States and Canada

Estimated Supply Growth

BCFD

30 25 20 15 10 5 0

‘05 ‘10 ‘15 ‘20

Arctic

Other Domestic

LNG

Arctic Gas

Alaska North Slope

Mackenzie Gas project

Other Domestic

Tight Gas

GOM Deep Shelf

LNG

Progressing regas terminals

Advanced trains with Qatar Petroleum

35

Upstream

Capitalize on Growing Gas Markets

Large Scale LNG Projects

Gross MTA

80 70 60 50 40 30 20 10 0

‘03 ‘04 ‘05 ‘06 ‘07 ‘08 ‘09 ‘10

Gross BCFD

10 8 6 4 2 0

Gorgon/Jansz Train 2 RG Train 7 Angola LNG Train 1 Gorgon/Jansz Train 1 QG Train 5 RG Train 6

QG Train 4

RG Train 5 RG Train 4 RG Train 3 RG 1-2

QG 1-3

Increasing share in growing LNG market

Strong partnership with Qatar Petroleum

Growing world-class LNG portfolio

Greater Gorgon/Jansz—Angola—Nigeria

EMNI (MTA) 7.0 7.7 8.2 8.4 9.0 13.0 16.4 19.5 including Arun

36

Upstream

Well-Positioned: Europe

Estimated Supply Growth

BCFD

60 50 40 30 20 10 0

‘05 ‘10 ‘15 ‘20

LNG

Russia/Caspian

New Pipeline

New Domestic Supply

RasGas Grows Continental Europe Presence

Italy—first offshore regas terminal

Zeebrugge—leveraging third-party infrastructure

Qatargas II Sets New Benchmarks

Largest sales to United Kingdom 30% reduction in unit cost Largest-ever energy-project financing

37

Upstream

Delivering Profitable Growth

MOEBD

5 4 3 2 1 0

‘04 ‘06 ‘08 ‘10

Russia/Caspian

Africa Europe Americas Middle East Asia Pacific

Result of robust inventory and strong processes

Geographically diverse

Enabled by functional expertise, integrated and leveraged worldwide

Delivering on our strategies

38

Upstream

Industry-Leading Performance

2000-04 Return on Capital Employed*

%

35 30 25 20 15 10 5 0

2004

XOM RDS BP CVX TOT

*Calculated on a consistent basis with ExxonMobil, based on public information. Competitor information estimated for 2004.

Industry’s largest and highest quality asset base

Rigorous investment discipline and selectivity

Leading-edge technology

39

Downstream

2004 Highlights

Record $5.7B earnings, $7.7B cash generation

ROCE 21%

Refinery throughput +4%

Petroleum product sales +3%

Operating excellence

- Best-ever safety

- Best-ever reliability

- Best-ever energy efficiency

More than $1B “self-help” captured

40

Downstream

Business Strategies

Global Scale and Integration

Margin Enhancement

Operating Cost Efficiency

Capital Discipline

Refining & Supply

Fuels Marketing

Lubricants & Specialties

41

Downstream

1999

“Self-Help” Advantages $1.2B

External Factors

“Self-Help”

Margin Enhancements

Op cost Efficiencies $5.7B

2004

42

Refining and Supply

2004 Overview

Global Scale 45 refineries in 25 countries

& Integration Larger, more conversion, more integration

than industry average

Margin Enhancement Captured additional $0.5B AT margin

Technology advancements

Positioned for growth in Asia Pacific

Cost Efficiency Industry-leading cash operating costs

Unplanned capacity loss reduced 20%

Capital Discipline Industry-leading project execution

Reduced working inventories

43

Refining and Supply

Structural Advantages

Configuration

% vs. Industry

80 60 40 20 0

Avg. Size Conversion Integration

Industry Avg.

XOM RDS / BP

Equity Capacity

MBD

6 4 2 0

XOM RDS BP

Distillation Conversion

Source: Oil and Gas Journal

44

Refining and Supply

Asset Utilization

Utilization

1998=100

102 100 98 96

‘98 ‘00 ‘02 ‘04

XOM Industry

Maintenance Cost & Availability

Cost 1998=100

120 100 80

‘98 ‘00 ‘02 ‘04

Availability

Cost

Availability 1998=100

101 100 99

Source: Solomon Data ; ‘04 Company estimate

Industry-leading reliability Turnaround management Throughput up 4%

Disciplined Reliability and Maintenance System Equipment Health Monitoring

45

Refining and Supply

Operating Efficiency

Cash Operating Costs

1998=100

100 90 80

‘98 ‘00 ‘02 ‘04

XOM Industry

Energy & Personnel

1998=100

100 95 90

Personnel

Energy

‘98 ‘00 ‘02 ‘04

Source: Solomon Data ; ‘04 Company estimate

Lower cash opex Continued improvement

Disciplined Global Energy Management System Continued workforce reductions

46

Refining and Supply

Margin Enhancement

Conversion Capacity Growth

1998=100

110 105 100

‘98 ‘00 ‘02 ‘04

Molecule Management Prize $M/Yr

500 100

375

250 125 0

‘02 ‘03 ‘04 ‘05 ‘06 ‘07 ‘08

On track to capture

~ $500M prize per year

Technology advancements Focused investments

Molecular fingerprinting Process modeling and optimization

47

Fuels Marketing

2004 Overview

Global Scale Retail, Industrial & Wholesale, Aviation, Marine

& Integration 100 countries on 6 continents

Margin Enhancement Disciplined site selection and operation

Non-fuels income up $30M

Cost Efficiency “Self-help” opex reductions of $200M

Consolidating support centers

Regular employees down 20% since 2000

Capital Discipline Focused market approach

Asset high-grading

retail sites down 15%

Capital employed down 15% since 2000

48

Fuels Marketing

Operating Efficiency

2000=100

100 85 70

‘00 ‘01 ‘02 ‘03 ‘04

Cumulative Opex Efficiencies Regular Employees $M

1200 600 0

Capital Discipline

2000=100 Total Retail Sites

100 85 70

‘00 ‘01 ‘02 ‘03 ‘04

Functional organization Common systems / processes Centralized support

Prioritized and focused investment Divestment of under-performing assets

49

Fuels Marketing

Retail Competitiveness

U.S. Breakeven Fuels Margin

2000=100

100 90 80

‘00 ‘01 ‘02 ‘03 ‘04

Lower on-site opex Higher non-fuels income

U.S. Focus Market Performance

Before=100

Before After

200 100 0

Market Volume Convenience Effectiveness Sales

Rigorous site selection Customer focused offering Disciplined operations execution

50

Lubricants and Specialties

2004 Overview

Global Scale Largest basestock supplier

& Integration 98% integrated with Refining

Growing position with global brands

Margin Enhancement Double-digit Mobil 1 growth

Double-digit growth in emerging markets

Strategic Global Alliances

Cost Efficiency Cost-to-serve down 5% in 2004

e-based ordering up 35% in 2004

Capital Discipline Capital employed down 20% since 2000

51

Lubricants and Specialties

Margin Enhancement

Synthetic Lubes Sales Growth

2000=100

150 125 100

‘00 ‘01 ‘02 ‘03 ‘04

ExxonMobil

Industry*

* ExxonMobil estimates

Mobil 1 leadership

Technology advantage

OEM endorsements

Finished Lubes Sales Growth

Emerging Markets

2000=100

160 140 120 100 80

‘00 ‘01 ‘02 ‘03 ‘04

Leveraged OEM relationships Expanded brand recognition Efficient supply chain

52

Lubricants and Specialties

Operating Efficiency

2000=100

100 75 50 25

Product Formulations

Blend Plants

‘00 ‘01 ‘02 ‘03 ‘04

Optimizing product offer Improving blend plant efficiency Leveraging best practices

Capital Employed

2000=100

100 90 80 70

‘00 ‘01 ‘02 ‘03 ‘04

Decreasing inventory

Reducing net receivables

53

Downstream

2004 Summary

Capital Employed* $B

40 20 0

XOM RDS BP

‘00 ‘04 ‘00 ‘04* ‘00 ‘04*

Reported Net Income $B

8 6 4 2 0

‘00 ‘04 ‘00 ‘04 ‘00 ‘04

Return on Capital Employed*

%

25 20 15 10 5 0

‘00 ‘04 ‘00 ‘04* ‘00 ‘04*

*Calculated on a consistent basis with ExxonMobil, based on public information. Competitor information estimated for 2004. Note: Impact of Allapattah reserve shown by red hatched box.

54

Chemical

2004 Highlights

Record earnings of $3.4B, ROCE of 23%

- Global coverage

- Feedstock and integration advantage

- Improved industry conditions

Record sales volume, up 5% versus 2003

Capex of $690M

- High return efficiency projects

- Low-cost expansions

- Specialty business growth

55

Chemical

Industry Outlook

The Industry Cycle*

Polyethylene, Polypropylene, Paraxylene

MT

200 150 100 50 0

Capacity Utilization

Demand

‘90 ‘95 ‘00 ‘05 ‘10

%

92 88 84 80 76

* ExxonMobil Estimates

Margin Trends*

2004 $/Ton

1000 500 0

PE

PX

‘90 ‘95 ‘00 ‘04

* ExxonMobil Estimates

56

Chemical

Business Strategies

Long-term strategy built on ExxonMobil’s core competencies

Unique portfolio of global integrated businesses

Strong synergies with upstream and downstream operations

Technology leadership

Focus on cost management, reliability and efficiencies Disciplined investment in advantaged projects

57

Chemical

Exceptional Mix

Business Mix

Earnings, $B

4.0 3.0 2.0 1.0 0.0

Cyclical Specialty

‘95 ‘00 ‘04

Geographic Mix

Sales volume, MT

14 10 6 2

1998 2004

Americas Europe Asia / MEAF

58

Chemical

Competitive Advantages

Site Integration

Products From Advantaged Feedstocks

Finished products from advantaged raw materials

Ethylene

2001=100

140 120 100

‘01 ‘02 ‘03 ‘04

Aromatics

2001=100

140 120 100

‘01 ‘02 ‘03 ‘04

Integrated

Non-Integrated

59

Chemical

Competitive Advantage

Technology

Lower Cost Processes

LRT-2 furnaces High pressure PE

Advantaged Feedstocks

Heavy feeds PXMax

Higher Value Products

Nexxstar Santoprene

60

Chemical

Supply Advantage

Reliability Gains

MT vs 2001

1.5 1.0 0.5 0.0

‘02 ‘03 ‘04

Manufacturing excellence

Reliability Efficiencies

Low-cost expansions

Supply Optimization

Intra and inter-regional supply chain optimization

Advantaged supply points Global marketing and sales presence Global optimization system

61

Chemical

Maximizing Returns

Premium Products Volume

2002=100

110

100

‘02 ‘03 ‘04

Productivity

Sales / Workforce

2001=100

120 110 100

‘01 ‘02 ‘03 ‘04

Market focus and customer needs segmentation

Growth of premium products

Technology advantage Product application expertise

Manufacturing improvements

Productivity gains Energy efficiency

62

Chemical

Growth Opportunities

Major Projects

Jose

Ras Laffan

Fujian

Singapore

Ethane Liquids

Low-cost expansions

- Added half of a steam cracker since 2001

Specialty Business growth

Major projects strategically located

- Feedstock

- Integration

- Market access

63

Chemical

Delivering Superior Returns

Capital Employed* $B

30 20 10 0

‘00 ‘04 ‘00 ‘04 ‘00 ‘04 ‘00 ‘04 ‘00 ‘04

XOM RDS BP CVX Dow

Reported Net Income $B

4 2 0

‘00 ‘04 ‘00 ‘04 ‘00 ‘04 ‘00 ‘04 ‘00 ‘04

Return on Capital Employed*

%

30 20 10 0

‘00 ‘04 ‘00 ‘04 ‘00 ‘04 ‘00 ‘04 ‘00 ‘04

*Calculated on a consistent basis with ExxonMobil, based on public information. Competitor information estimated for 2004.

64

Business Model

ExxonMobil Approach

DisciplinedInvestment

Growth in Shareholder Value

Operational Excellence

Industry Leading Returns

Superior Cash Flow

65

Long-Term Perspective

Industry driven by long-term trends

Evolving LNG market

Key levers for long-term success in refining

Seeing past the cycle in Chemical

66

Structural Advantage

Global Functional Organization

Strongest suite of proprietary technologies Industry-leading resource base Unmatched financial flexibility Integration of refining and chemical assets Unparalleled optimization capability

67

Growing Advantage

Changing nature of market plays to ExxonMobil’s strengths Consistent rapid improvement Leverage from technology

Withdrawal of competitors from key markets and business lines

68

Long-Term Advantage for Shareholders

5-Year Rolling Average ROCE*

%

20 18 16 14 12 10 8 6

‘00 ‘01 ‘02 ‘03 ‘04

ExxonMobil

RDS

BP

CVX

20-Year Annualized Total Return vs. Volatility of Returns

Lower Volatility

Higher Volatility

%

14 18 22 26

S&P 500

10% 12% 14% 16% 18%

Lower Return Higher Return

*Calculated on a consistent basis with ExxonMobil, based on public information.

Competitor information estimated for 2004.

69

Long-Term Advantage for Shareholders

20-Year Total Market Capital $B

400 350 300 250 200 150 100 50 0

‘84 ‘86 ‘88 ‘90 ‘92 ‘94 ‘96 ‘98 ‘00 ‘02 ‘04

ExxonMobil

RDS

BP

CVX

* Total market capital at year-end. Pre-merger figures are for XON, BP, and CHV.

EX-99.3

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 quantified special items. Earnings excluding the aforementioned items is a non-GAAP financial measure, and is included to facilitate comparisons of base business performance across periods. We also refer to earnings excluding merger expenses, discontinued operations, accounting change 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.

Information for “Downstream 2004 Summary” chart is shown below.

Total Downstream - 2004	Earnings After Income Taxes		Average Capital Employed	Return on Average Capital Employed
	(millions of dollars)			(percent)
Reported	5,706		27,173	21.0	%
Allapattah litigation reserve	(550	)
Excluding Allapattah litigation reserve	6,256		27,173	23.0	%

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, interest expense and separately reported merger-related expenses. 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. In 2004, cost increases associated with higher energy prices, adverse foreign exchange impacts, and new operations were partly offset by efficiency initiatives captured in all business lines.

Reconciliation of operating costs

	2004	2003	2002
	(millions of dollars)
From ExxonMobil’s Consolidated Statement of Income
Total costs and other deductions	256,794	214,772	186,996
Less:
Crude oil and product purchases	139,224	107,658	90,950
Merger-related expenses	—	—	410
Interest expense	638	207	398
Excise taxes	27,263	23,855	22,040
Other taxes and duties	40,954	37,645	33,572
Income applicable to minority and preferred interests	776	694	209
Subtotal	47,939	44,713	39,417
ExxonMobil’s share of equity-company expenses	4,209	3,937	3,800
Total operating costs excluding merger expenses	52,148	48,650	43,217
Components of operating costs
	2004	2003	2002
	(millions of dollars)
From ExxonMobil’s Consolidated Statement of Income
Production and manufacturing expenses	23,225	21,260	17,831
Selling, general, and administrative expenses	13,849	13,396	12,356
Depreciation and depletion	9,767	9,047	8,310
Exploration expenses, including dry holes	1,098	1,010	920
Subtotal	47,939	44,713	39,417
ExxonMobil’s share of equity-company expenses	4,209	3,937	3,800
Total operating costs excluding merger expenses	52,148	48,650	43,217

- 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.

	2004		2003		2002
	(millions of dollars)
Business uses: asset and liability perspective
Total assets	195,256		174,278		152,644
Less liabilities and minority share of assets and liabilities
Total current liabilities excluding notes and loans payable	(39,701	)	(33,597	)	(29,082	)
Total long-term liabilities excluding long-term debt and equity of minority and preferred shareholders in affiliated companies	(41,554	)	(37,839	)	(35,449	)
Minority share of assets and liabilities	(5,285	)	(4,945	)	(4,210	)
Add ExxonMobil share of debt-financed equity-company net assets	3,914		4,151		4,795
Total capital employed	112,630		102,048		88,698
Total corporate sources: debt and equity perspective
Notes and loans payable	3,280		4,789		4,093
Long-term debt	5,013		4,756		6,655
Shareholders’ equity	101,756		89,915		74,597
Less minority share of total debt	(1,333	)	(1,563	)	(1,442	)
Add ExxonMobil share of equity-company debt	3,914		4,151		4,795
Total capital employed	112,630		102,048		88,698

RETURN ON AVERAGE CAPITAL EMPLOYED (ROCE)

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

Return on Average Capital Employed

	2004		2003		2002
	(millions of dollars)
Net income	25,330		21,510		11,460
Financing costs (after tax)
Third-party debt	(137	)	(69	)	(81	)
ExxonMobil share of equity companies	(185	)	(172	)	(227	)
All other financing costs – net(1)	54		1,775		(127	)
Total financing costs	(268	)	1,534		(435	)
Earnings excluding financing costs	25,598		19,976		11,895
Average capital employed	107,339		95,373		88,342
Return on average capital employed – corporate total	23.8	%	20.9	%	13.5	%

(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 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 COSTS

Finding costs per oil-equivalent barrel is a performance measure that is calculated using the Exploration portion of Upstream capital and exploration expenditures divided by new field resource additions (in oil-equivalent barrels). ExxonMobil refers to new discoveries and acquisitions of discovered, but undeveloped, resources as new field resource additions. It 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.

	2004	2003	2002
Exploration portion of Upstream capital & exploration expenditures (millions of dollars)	1,283	1,215	1,310
New field resource additions (millions of oil-equivalent barrels)	2,940	2,110	2,150
Finding cost per oil-equivalent barrel (dollars)	0.44	0.58	0.61

LIQUIDS AND NATURAL GAS RESERVES

In this report, we use the term “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 reserves when we have made significant funding commitments for the related projects. In this report, we aggregate 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, oil and gas 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 757 million barrels at year-end 2004, 781 million barrels at year-end 2003, 800 million barrels at year-end 2002, 821 million barrels at year-end 2001, and 610 million barrels at year-end 2000. We determine reserves based on our long-term view of future price levels consistent with our investment decisions. Based on Securities and Exchange Commission guidance, ExxonMobil is also stating, for the first time, our 2004 results to reflect the impacts to the proved reserve base utilizing December 31 liquids and natural gas prices (“year-end price/cost revisions”). On this basis, 2004 year-end reserves, including year-end price/cost revisions, totaled 21.7 billion oil-equivalent barrels. Excluding year-end price/cost revisions, 2004 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 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.

RESERVES REPLACEMENT RATIO

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 operations in both additions and production volumes. See the definition of “liquids and natural gas reserves” above.

- 3 -

RESERVES REPLACEMENT COSTS

Reserves replacement costs per oil-equivalent barrel is a performance measure ratio. 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 reserves” above.

	2004	2003	2002
	(millions of dollars)
Costs incurred
Property acquisition costs	134	45	187
Exploration costs	1,255	1,181	1,163
Development costs	9,122	9,856	8,101
Total costs incurred	10,511	11,082	9,451
	(millions of barrels)
Oil-equivalent reserves additions
Performance-related revisions	140	619	597
Improved recovery	28	116	95
Extensions/discoveries	1,809	961	1,210
Purchases	11	2	—
Total oil-equivalent reserves additions	1,988	1,698	1,902
Reserves replacement costs	5.29	6.53	4.97

USES OF CASH

“Uses of cash” means the net sum of additions to property, plant and equipment; additional investments and advances net of collection; changes in minority interests; the net cost of common stock acquired to offset the dilutive impact of shares issued in conjunction with company benefit plans; effects of exchange rate changes on cash; and cash dividends to ExxonMobil shareholders and to minority interests from the Consolidated Statement of Cash Flows. It does not include increases in restricted cash and cash equivalents, which relates to the appeal of pending litigation.

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.

	2004	2003	2002
	(millions of dollars)
Net cash provided by operating activities	40,551	28,498	21,268
Sales of subsidiaries, investments and property, plant, and equipment	2,754	2,290	2,793
Cash flow from operations and asset sales	43,305	30,788	24,061

- 4 -

Exxon Mobil Corporation

FINANCIAL HIGHLIGHTS

(millions of dollars)	2004		2003		2002	2001	2000
Sales and other operating revenue	291,252		237,054		200,949	208,715	227,596
Net income	25,330		21,510		11,460	15,320	17,720
Cash flow from operations and asset sales (1)	43,305		30,788		24,061	23,967	28,707
Capital and exploration expenditures (1)	14,885		15,525		13,955	12,311	11,168
Cash dividends to ExxonMobil shareholders	6,896		6,515		6,217	6,254	6,123
Common stock purchases (gross)	9,951		5,881		4,798	5,721	2,352
Research and development costs	649		618		631	603	564
Cash and cash equivalents at year end (2)	18,531		10,626		7,229	6,547	7,080
Total assets at year end	195,256		174,278		152,644	143,174	149,000
Total debt at year end	8,293		9,545		10,748	10,802	13,441
Shareholders’ equity at year end	101,756		89,915		74,597	73,161	70,757
Average capital employed (1)	107,339		95,373		88,342	88,000	87,463
Market valuation at year end	328,128		269,294		234,101	267,577	301,239
Regular employees at year end (thousands)	85.9		88.3		92.5	97.9	99.6
FINANCIAL RATIOS
	2004		2003		2002	2001	2000
Net income per common share (dollars)	3.91		3.24		1.69	2.23	2.55
Net income per common share - assuming dilution (dollars)	3.89		3.23		1.68	2.21	2.52
Return on average capital employed (1) (percent)	23.8		20.9		13.5	17.8	20.6
Net income to average shareholders’ equity (percent)	26.4		26.2		15.5	21.3	26.4
Debt to capital (3) (percent)	7.3		9.3		12.2	12.4	15.4
Net debt to capital (4) (percent)	(10.7	)	(1.2	)	4.4	5.3	7.9
Current assets to current liabilities	1.40		1.20		1.15	1.18	1.06
Fixed charge coverage ratio (times)	36.1		30.8		13.8	17.7	15.6

(1) See Frequently Used Terms on pages 1 through 4.

(2) Excluding restricted cash of $4,604 million.

(3) Debt includes short and long-term debt. Capital includes short and long-term debt, shareholders’ equity, and minority interests.

(4) Debt net of cash, excluding restricted cash. The ratio of net debt to capital including restricted cash is (16.3) percent for 2004.

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Exxon Mobil Corporation

Financial Summary

FUNCTIONAL EARNINGS

(millions of dollars)	2004 Quarters
Net Income (U.S. GAAP)	First		Second		Third		Fourth		2004		2003		2002		2001		2000
Upstream
United States	1,154		1,237		1,173		1,384		4,948		3,905		2,524		3,933		4,542
Non-U.S.	2,859		2,609		2,756		3,503		11,727		10,597		7,074		6,803		8,143
Total	4,013		3,846		3,929		4,887		16,675		14,502		9,598		10,736		12,685
Downstream
United States	392		907		11		876		2,186		1,348		693		1,924		1,561
Non-U.S.	612		600		840		1,468		3,520		2,168		607		2,303		1,857
Total	1,004		1,507		851		2,344		5,706		3,516		1,300		4,227		3,418
Chemical
United States	118		148		329		425		1,020		381		384		298		644
Non-U.S.	446		459		680		823		2,408		1,051		446		409		517
Total	564		607		1,009		1,248		3,428		1,432		830		707		1,161
Corporate and financing	(141	)	(170	)	(109	)	(59	)	(479	)	1,510		(442	)	(142	)	(538	)
Merger expenses	0		0		0		0		0		0		(275	)	(525	)	(920	)
Discontinued Operations	0		0		0		0		0		0		449		102		184
Extraordinary Gain	0		0		0		0		0		0		0		215		1,730
Accounting Change	0		0		0		0		0		550		0		0		0
Net income (U.S. GAAP)	5,440		5,790		5,680		8,420		25,330		21,510		11,460		15,320		17,720
Net income per common share (dollars)	0.83		0.89		0.88		1.31		3.91		3.24		1.69		2.23		2.55
Net income per common share - assuming dilution (dollars)	0.83		0.88		0.88		1.30		3.89		3.23		1.38		2.21		2.52
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		0		0		0		1,700		(215	)	0		0
Total	0		0		0		0		0		1,700		(215	)	0		0
Downstream
United States	0		0		(550	)	0		(550	)	0		0		0		0
Non-U.S.	0		0		0		0		0		0		0		0		0
Total	0		0		(550	)	0		(550	)	0		0		0		0
Chemical
United States	0		0		0		0		0		0		0		0		0
Non-U.S.	0		0		0		0		0		0		0		0		0
Total	0		0		0		0		0		0		0		0		0
Corporate and financing	0		0		0		0		0		2,230		0		0		0
Merger expenses	0		0		0		0		0		0		(275	)	(525	)	(920	)
Discontinued Operations	0		0		0		0		0		0		449		102		184
Extraordinary Gain	0		0		0		0		0		0		0		215		1,730
Accounting Change	0		0		0		0		0		550		0		0		0
Corporate total	0		0		(550	)	0		(550	)	4,480		(41	)	(208	)	994
Earnings Excluding Merger Effects, Discontinued Operations, Accounting Change, and Other Special Items
Upstream
United States	1,154		1,237		1,173		1,384		4,948		3,905		2,524		3,933		4,542
Non-U.S.	2,859		2,609		2,756		3,503		11,727		8,897		7,289		6,803		8,143
Total	4,013		3,846		3,929		4,887		16,675		12,802		9,813		10,736		12,685
Downstream
United States	392		907		561		876		2,736		1,348		693		1,924		1,561
Non-U.S.	612		600		840		1,468		3,520		2,168		607		2,303		1,857
Total	1,004		1,507		1,401		2,344		6,256		3,516		1,300		4,227		3,418
Chemical
United States	118		148		329		425		1,020		381		384		298		644
Non-U.S.	446		459		680		823		2,408		1,051		446		409		517
Total	564		607		1,009		1,248		3,428		1,432		830		707		1,161
Corporate and financing	(141	)	(170	)	(109	)	(59	)	(479	)	(720	)	(442	)	(142	)	(538	)
Corporate total	5,440		5,790		6,230		8,420		25,880		17,030		11,501		15,528		16,726
Earnings per common share (dollars)	0.83		0.89		0.96		1.31		3.99		2.57		1.70		2.27		2.40
Earnings per common share - assuming dilution (dollars)	0.83		0.88		0.96		1.30		3.97		2.56		1.69		2.25		2.37

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Exxon Mobil Corporation

RETURN ON AVERAGE CAPITAL EMPLOYED (1) BY BUSINESS

(percent)	2004	2003	2002	2001	2000
Upstream
United States	37.0	28.9	19.0	30.4	35.3
Non-U.S.	31.5	31.0	23.7	25.1	28.7
Total	32.9	30.4	22.3	26.8	30.8
Downstream
United States	28.6	16.7	8.6	25.0	19.6
Non-U.S.	18.0	11.5	3.4	12.4	9.4
Total	21.0	13.0	5.0	16.1	12.3
Chemical
United States	19.4	7.3	7.3	7.2	11.4
Non-U.S.	25.7	11.8	5.3	5.8	6.3
Total	23.5	10.2	6.1	6.4	8.4
Corporate and financing	—	—	—	—	—
Discontinued operations	—	—	63.2	7.2	12.3
Corporate total	23.8	20.9	13.5	17.8	20.6

(1) Capital employed consists of shareholders’ equity and debt, including ExxonMobil’s share of amounts applicable to equity companies. See Frequently Used Terms on pages 1 through 4.

AVERAGE CAPITAL EMPLOYED (1) BY BUSINESS

(millions of dollars)	2004	2003	2002	2001	2000
Upstream
United States	13,355	13,508	13,264	12,952	12,864
Non-U.S.	37,287	34,164	29,800	27,077	28,354
Total	50,642	47,672	43,064	40,029	41,218
Downstream
United States	7,632	8,090	8,060	7,711	7,976
Non-U.S.	19,541	18,875	17,985	18,610	19,756
Total	27,173	26,965	26,045	26,321	27,732
Chemical
United States	5,246	5,194	5,235	5,506	5,644
Non-U.S.	9,362	8,905	8,410	8,333	8,170
Total	14,608	14,099	13,645	13,839	13,814
Corporate and financing	14,916	6,637	4,878	6,399	3,198
Discontinued operations	0	0	710	1,412	1,501
Corporate total	107,339	95,373	88,342	88,000	87,463
Average capital employed applicable to equity companies included above	18,049	15,587	14,001	13,902	15,330

(1) Average capital employed is the average of the beginning and end-of-year business segment capital employed. See Frequently Used Terms on pages 1 through 4.

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