EXHIBIT 99
Exxon Mobil Corporation
Presentations and Q&A Session
Analyst Meeting
New York, NY
March 10, 2004
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EXXONMOBIL PRESENTERS
Lee Raymond, Chairman and CEO
Rex Tillerson, President
Harry Longwell, Executive Vice President
Ed Galante, Senior Vice President
CAUTIONARY STATEMENT
Outlooks, projections, estimates, targets, and business plans described in these presentations are forward-looking statements. Actual future results, including resource additions and recoveries; capital expenditures; production rates, mix, and growth; project plans, timing, costs, capacities, and schedules; demand growth and mix; revenue enhancements and cost efficiencies; and the impact of new technologies could differ materially due to a number of factors. These include changes in market conditions affecting the oil and gas industry; changes in law or government regulation; the outcome of commercial negotiations; political events and local security concerns; the actions of competitors; 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. References to resources, the resource base, and oil-equivalent barrels (other than historical production figures) include quantities of oil and gas that are not yet classified as proved reserves but that we believe will likely be produced in the future. References to proved reserves include tar sands reserves associated with the Canadian Syncrude operation, which are shown separately as mining reserves in our SEC filings. Additional information on terms we use in this presentation, including return on capital employed and information provided under SEC Regulation G, is posted on our website under the heading “Frequently Used Terms”.
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PRESENTATIONS
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Morning. I'd like to welcome everyone who has joined us for today's meeting in person, by teleconference or on the Internet.
As you know, ExxonMobil has a history of consistently delivering industry-leading performance. We had another outstanding year in 2003.
ExxonMobil continued to be the industry leader in safety performance.
In 2003, we had the lowest number of safety incidents in our history. We also set a record with earnings of $21.5 billion, an industry leading return on capital employed of 21% and cash flow from operations and asset sales in excess of $30 billion.
We continued to successfully advance profitable growth opportunities that meet our investment criteria.
In 2003, we invested $15.5 billion in capital projects and exploration activities. Progress on our broad portfolio of projects is on track. These projects represent the base business for ExxonMobil in the decades ahead.
We maintained our commitment to our shareholders to create long-term, sustainable value. Last year we returned a record $11.5 billion to shareholders through dividend payments and share purchases.
We will continue to deliver these kinds of results in the future because of the progress we make each year in advancing a wide range of initiatives. We more than replaced production for the tenth consecutive year.
In 2003, we started up 16 Upstream projects. These projects are expected to add net daily peak production of more than 450,000 barrels of crude oil per day and 600 million cubic feet per day of natural gas.
Major Upstream projects now underway are expected to develop up to 25 billion net oil-equivalent barrels.
We anticipate about 30 startups in the next three years, with many in the resource rich areas such as West Africa, Qatar, the Caspian and Russia.
Our Downstream earnings tripled versus 2002 and were the second highest ever.
In a year of volatile industry conditions, this result demonstrates the organization's focus on operational efficiency, margin improvement initiatives and prudent capital management.
Our Chemical business achieved sales matching their record levels in 2002 and had their highest earnings in five years.
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Our global functional organization delivered more than $2 billion of before-tax cost efficiencies and revenue enhancements, exceeding our expectations. All of our businesses made strong contributions to the continuing success of the company in 2003.
At ExxonMobil, nothing is more important than the safety and health of our employees, our contractors and the people who live and work in the areas where we operate. Safety remains our top priority.
We are convinced that the discipline required to achieve outstanding safety results carries over into everything else that we do.
We continue to lead the industry in safety performance and once again, set a record for the fewest safety incidents in 2003.
Despite this achievement, we will continue to focus our safety management systems to achieve our goal that nobody gets hurt.
Safety is an excellent example of our organization's ability to set high expectations, clearly communicate them to every employee and deliver results.
By now, I expect that you are familiar with our long-standing business model. It hasn't changed over the years, and it won't in the future.
The continuing combination of disciplined investment decisions with a focus on long-term fundamentals and the importance of operational excellence in all aspects of our business lead to solid returns and superior cash flow.
We do not need to reinvent our business model each year. We also don't need to change the metrics we use to measure performance. We do not incur the cost of refocusing our organization every few years on a new set of priorities.
The core values that provide the backbone of our business model are firmly established in our globally aligned functional organization.
Simply put, our model is a transparent and straightforward approach to doing business. However, it appears to be difficult to duplicate and hence provides us with a sustainable competitive advantage.
We have now completed five years since the merger of Exxon and Mobil. Since we reappraise all of our investment decisions, it seems appropriate to look at our performance over this period.
Some have identified the ExxonMobil merger as one of the few clearly successful mega-mergers, if not the most successful.
The foundation for the success of the merger is the combination of two complementary organizations and sets of assets. It provided an opportunity for a step change scale improvement in our combined operations.
We were also able to improve on capital productivity through rigorous asset appraisal and investment selectivity.
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We maintained the strengths of the globally recognized brands of each heritage company. Other mergers in our industry incurred significant rebranding costs and lost brand equity that took years to create.
Another key strategy came from the integration of two world class technology programs. We built on this foundation and are moving forward with the best ideas from each. We also leveraged this combined technology set across a much larger asset base.
Our functional organization enables the rapid sharing of best practices around the world. We have retained the best and the brightest to staff the organization.
Our people continue to deliver substantial benefits by taking costs out of the business and finding new ways to increase the value of our assets.
Finally, I think everyone would agree that without the effort and commitment of our people, the combination of just assets would never have resulted in the company we call ExxonMobil today.
And we are far from done as new ideas are continually being generated across all of our businesses. We recognize the change is a constant.
We have made the ability and flexibility to change the fundamental strength of our company and it gives us a competitive advantage.
Since the merger, we have generated over $120 billion in cash. We have invested roughly $66 billion or about 55% to improve our base and provide profitable growth opportunities for the future.
We have retained approximately 10% to increase our flexibility to add attractive investments and we have distributed $47 billion to our shareholders. To put that in context, our shareholder distributions alone in the last five years have exceeded the market capitalization of 98% of the companies currently trading on the New York Stock Exchange.
In the last five years, the company has earned $74 billion. This represents the combined earnings of nearly 400 of the 500 companies in the S&P 500 over the same period.
We have captured $10 billion in synergies and efficiencies and we have added nine billion oil-equivalent barrels to our industry-leading reserves base. We continue our relentless focus on controlling costs.
Since the merger, we have successfully held cash costs [Operating Costs excluding depreciation and depletion] below inflation. At the same time, we have started up several major Upstream projects and added major capacity expansions in our Chemical business.
At the end of 1999, Exxon and Mobil began the merger with a combined workforce of 107,000 people. At the end of 2003, that number was 88,000, a reduction of 18%.
This was not the result of a one-time restructuring plan. Instead, it has been the relentless pursuit of efficiency capture as we learn to work smarter in the normal course of our business.
We are able to operate a larger asset base with fewer people because of the efficiencies of our functional organization. Without geographic boundaries, we can rapidly deploy our people to the areas of each business that will yield the highest return.
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In 2003, we delivered $1.2 billion of before tax cost efficiencies, exceeding the commitment I mentioned to you a year ago. We will continue to find opportunities to improve and plan to deliver an additional $1 billion in cost efficiencies in 2004.
We have also captured significant value from our approach to investments and asset management.
We regularly conduct reviews to insure that all assets adequately contribute to our results. Through this appraisal process, we identify assets that could be considered for divestment.
The approach we take to continuously high grade our asset base yields very positive returns. Over this period, we have completed discretionary divestments of $5 billion while adding $3 billion to the bottom line.
This process has created a very efficient capital base. The value in examining the portfolio on a regular basis is apparent. Others have seen the need for what looks like fire sales from our perspective.
Oftentimes their actions have also resulted in significant asset write downs and I'll have more to say about that later.
ExxonMobil's core fundamental objective is long-term growth in shareholder value. One way we provide value that sets us apart from competition is the consistency of our share purchase program.
Since the merger, we have returned $16 billion to shareholders and reduced shares outstanding by about 6% [added $0.13 to earnings per share for 2003].
In the third quarter of 2003, we increased the rate of share buybacks to $1.5 billion per quarter and continue at that pace today.
In total, we have returned $47 billion to our shareholders over the past five years. That's about equal to the market capitalization of DaimlerChrysler.
In 2003, we raised the quarterly dividend 9%. Together with share purchases, we provided a total yield of 4.9%.
Our average dividend yield over the last five years by itself exceeded the average of the 50 largest U.S. corporations.
Our record of increasing the dividend payment in each of the last 21 years is unmatched among international oil companies. Our compound annual dividend growth rate of 4.7% over the last 20 years outpaces the 3.1% growth in the U.S. Consumer Price Index.
In summary, I think the facts speak for themselves on what the merger has meant for our shareholders.
Our industry leading returns have generated consistently strong cash flows throughout the business cycle.
We continue to leverage our proprietary technology, geographic diversity and business line balance. Some of you like to refer to our cash position as a problem. We don't share this view.
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Our financial strength is unique in the industry [ExxonMobil Operating Cash Flow Surplus (Sources of Cash less Uses of Cash) equaled $10.5 billion in 2003. Net Debt to Capital of -1.2% at yearend 2003]. The higher leverage of our competitors impacts their ability to make large financial commitments when attractive investment opportunities emerge.
Strong business results and our disciplined approach to financial management insure that we can maintain financial strength at any stage of the industry cycle. What I told you last year bears repeating.
We are not going to invest in low-return projects. We won't buy volume and we won't start and stop our dividends or share purchase program.
One area where we continue to focus attention is our consistent commitment to technology. It surprises me how willingly some forego the opportunities presented by proprietary research.
It is the lifeblood that provides a company with the tools to compete in increasingly difficult environments and to meet new product demands.
We balance our investment [$618 million in 2003] between technology extensions, which can be rapidly deployed to our existing operations, and breakthrough research, areas that can have a significant and lasting impact on the corporation and the industry.
In the Upstream, we support a full spectrum of initiatives covering exploration through enhanced recovery and field depletion applications. This emphasis on technology opens new frontiers for cost effective resource development, deeper water, arctic regions and other challenging environments.
In the Downstream and Chemical, we are leveraging technologies to meet market needs whether it's an area of new product development or to improve our manufacturing processes.
We believe there is a direct correlation between research and leading results in all of our businesses. Often we are asked how we make technology investments within our disciplined financial decision-making framework.
The answer is straightforward. Our technology and development efforts are matched to our business needs through rigorous prioritization. We apply the same stewardship methods to our technology portfolio that we use throughout the rest of our business. This commitment underscores our belief that the role of science and technology in our industry is absolutely vital if we are to provide reliable and affordable energy supplies.
The overall effort is managed to maximize value. Our emphasis on proprietary technology is key to maintaining our competitive advantage and a contributor to future earnings growth.
Our geographic diversity, along with the scale of our operations in each region, provides a natural hedge as it mitigates the corporation's risks from changes in commodity prices, business cycles and regional market conditions.
Our presence in all regions of the world also provides us with an efficient platform for investing in any profitable opportunity that meets our criteria.
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We have a breadth of experience that makes ExxonMobil a partner of choice among many of the governments and national companies with whom we do business.
Our global functional organization allows us to deploy capital and human resources efficiently. It also affords us the ability to quickly roll out improvements and best practices throughout our diverse operations around the world.
The company's functional mix results in earnings that are less sensitive to downturns in one segment of the business or geography. The value of the three business lines is particularly evident when you look over the past several years.
You don't have to look too far back to see commodity prices significantly lower than today. In a declining commodity price environment, both our Downstream and Chemical businesses were clearly strong earnings contributors.
Maintaining this balance provides us with a competitive advantage regardless of where we are in the business cycle. In 2003, we invested over $15 billion in capital projects and exploration activities and expect to stay at that level for the next couple of years.
We are pursuing all attractive opportunities with the same disciplined investment approach that has delivered results in the past.
In the Upstream, we will continue to invest in our profitable base business. We also have an unprecedented number of development startups over the next several years.
In Downstream and Chemical, our focus is on making selective and resilient investments to enhance returns above those achieved by the industry. Our disciplined approach continues through all phases of project implementations from design, construction through startup and ongoing operations to insure that we obtain the maximum value from our investments. Project reappraisals are performed to ensure relevant lessons are learned and improvements are incorporated into future projects.
The strength of our balance sheet ensures that we are not constrained by a lack of financial flexibility. However, one thing is clear.
We do not let short-term conditions influence our investment decisions. Instead, our investment strategy focuses on high return opportunities.
As we all know, any investment decision carries with it the consideration of risk and reward.
Conventional wisdom is that higher risk should yield higher reward and conversely lower reward should follow lower risk.
However, as with many aspects of our business, we don't always accept the old adages. That's particularly true when you look at the total return of our shares over the last two decades. Over this 20-year period, ExxonMobil stock has earned nearly a 16% return.
We have accomplished this with far lower risk [volatility of return] than our competition and at the same level as the entire S&P 500. I think it's fair to say there aren't many companies, if any, that can provide shareholders and the potential investors that kind of track record.
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As you well know by now, in our view the best measure of performance in our industry is return on capital employed. For a fleeting moment, I thought many of our competitors agreed with us.
Now it seems some are abandoning this analytical framework in favor of no metric, but I would ask you, what measure is better? From our perspective, there isn't one.
The facts are that an industry-leading return on capital employed demonstrates the overall ability of a company to not only generate income, but to do so on a highly efficient capital base. That's something we have done consistently for years [ExxonMobil 5-year rolling average ROCE (1999-2003) = 16.6%].
One way to increase the return on capital employed is to reduce capital employed and there are a number of ways to do that.
Among our major competitors, write-downs seem to be a popular method for accomplishing this. Our competitors have made cumulative one-time write-downs of nearly $30 billion in the last 10 years, $16 billion in the last five years. This by the way is the equivalent of the shareholders' equity in Procter & Gamble.
I'm curious to know what the competition's returns would look like if these numbers were added back to their capital base.
Now I know that some of you are a bit more short term focused and may be tired of my insistence on looking at our business over the long term. I just can't get overly excited about each quarter's results, but you'll be happy to see that once in a while, my arm can be twisted. Here we show a three-year rolling average comparison [ExxonMobil 3-year rolling average ROCE (2001-2003) = 17.4%]. That's about as short a timeframe as is appropriate to look at in our industry.
What you see here is that ExxonMobil captures more value from its assets in any price environment. Even with record levels of capex, our disciplined approach helps us to avoid the pitfall of making investments that significantly dilute returns. Above all else, our results distinguish us from competition.
This concludes my opening remarks on the corporation's performance. Rex and Ed will now take you through the business line reviews. I'll wrap up the formal remarks just after our break and then we'll open up the session for questions.
Rex, the Upstream.
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Rex Tillerson - Exxon Mobil Corporation - President
Thank you Lee. Good morning everyone. It is of course my pleasure to discuss with you our Upstream business this morning.
Most of you know, but perhaps it's worth reminding the Upstream is comprised of four global functional organizations, Exploration, Development, Production, and Gas & Power Marketing. All four are supported by our Upstream Research company. The results which I'll describe this morning represent the collective integrated activities of all these companies.
Within my discussion today, I'll address our 2003 performance and the prevailing business environment that was the backdrop for these results. I'll review our Upstream strategies and I'll share with you specific 2003 successes and describe the future opportunities that we expect to deliver, the volumes for the current decade and beyond.
Though the business conditions and opportunities vary year on year, our fundamental strategies continue to deliver a competitive advantage.
I'll begin with the discussion of our Upstream business with a high level summary of the 2003 results. 2003 was a remarkable year for the Upstream with record earnings of $14.5 billion. Oil and gas operations accounted for $14.2 billion and our power and coal business delivered $300 million.
These earnings were up more than 50% from 2002 primarily due to the continued high price environment and the gain associated with the transfer of our shareholdings in Ruhrgas. Return on capital employed was over 30% and incidentally, our Upstream return on capital employed for the last five years averaged 25%.
Upstream capital and exploration expenditures, driven largely by investments in major new development projects, as well as our profitable base, totaled $12 billion.
Liquids production was 2.5 million barrels per day, an increase of about 1% versus last year, and gas available for sale was over 10 billion cubic feet per day, representing a decrease of 3% year-on-year.
About half of this decline in gas sales year-on-year was due to market demand factors in Europe and Southeast Asia where we had additional capacity that went unsold. The balance of the decline in gas volumes reflected the continued decline of volumes in North America. Our oil-equivalent production of over four million barrels per day was the highest among non-governmental competitors.
Producible volumes, excluding the effects of extraordinary operational outages, the Venezuelan strike and some entitlement effects driven by the higher prices would actually have been up 1%.
Resource additions were in excess of two billion oil-equivalent barrels and our proved reserve adds were 1.7 billion oil-equivalent barrels.
Excluding property sales, reserve replacement totaled 107% of production and as Lee has already mentioned, this marks the tenth year in a row that proved reserves additions have more than replaced our produced volumes.
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To place these results in perspective, it is relevant to examine the business environment in which we operated last year.
2003 saw a continuation of the relatively high prices for both crude oil and natural gas.
Last year, Brent averaged around $29 a barrel which was $4 a barrel higher than 2002 and our realizations also were up $4 per barrel [ExxonMobil average realization $27/bbl in 2003 vs. $23/bbl in 2002]. Sustainability of this crude price trend is difficult if not impossible to predict and future investments must be tested against price bases that reflect the fundamentals of long-term supply and demand. In North America, Henry Hub prices averaged over $5 a million BTU, an increase of about $2.20 over 2002 [ExxonMobil average realization $4.1/MBTU in 2003 vs. $3.0/MBTU in 2002].
The higher natural gas prices, which on average appear to be near parity with crude oil, seem also to be reflecting a tightening supply and demand balance in North America resulting from a steady industry wide decline of the resource base and a reduction in yield from conventional opportunities over the last five years. This is also the conclusion of the National Petroleum Council gas study which was completed last year.
The implications of which are a need for greater imports of natural gas as well as future supplies of Arctic gas from Canada and Alaska. And finally, the weak U.S. dollar has contributed to higher operating and capital costs, but I hasten to add that on balance, the net forex effect for the Upstream in 2003 was a positive $138 million to earnings reflecting the strength of our globally diverse holdings.
Regardless of the business environment, our Upstream strategies continue to deliver a competitive advantage and are the foundation for our current and future results. These strategies have remained unchanged for more than a decade and are supported by an unparalleled commitment to technology, our global functional organization, our opportunity rich portfolio, our dedication to flawless executions and operations integrity, and a continued focus on cost management in our base business.
Our Upstream resource holdings are diverse. Our current asset base includes over 60,000 productive wells in over 1,800 fields and nearly 600 offshore platforms. Our industry-leading resource base of 72 billion oil-equivalent barrels and proved reserves of 22 billion oil-equivalent barrels provides a diverse source of current producing volumes and future development opportunities.
It's important to note that a little more than 30% of our resource base is proved and of the resource base and the proved reserves, both are comprised of about 60% liquids and 40% gas. And in the proved reserves, over 60% are booked as proved, developed. We produced over four million oil-equivalent barrels per day last year from 25 countries representing a proved reserves to production ratio of over 14.
The global exploration company continued to explore for, find and add significant new resources in 2003. Net resource additions last year totaled 2.1 billion oil-equivalent barrels, the fourth consecutive year of greater than two billion barrel adds. 124 exploratory wells were drilled last year with a success rate of greater than 50%.
Key discoveries were made in Angola, Nigeria, Kazakhstan and Brazil. By the bit discoveries were 1.7 billion oil-equivalent barrels of the 2.1 billion total. Other important resource adds from already discovered fields included Qatar, Canada and the U.S. Program finding costs remained low and continued to decline with 2003 finding costs of only 58 cents an oil-equivalent barrel.
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For the five-year period of 1999 to 2003, we've added over 10 billion oil-equivalent barrels to the ExxonMobil resource base at an average finding cost of 71 cents a barrel. These adds were also from geographically diverse locations. The two major growth areas, Africa and the Caspian account for almost 50% of the total.
However, significant adds continue to be made in the mature areas of North America and Europe. It is from this large diverse inventory of quality resources that we select development opportunities and apply new technologies to move the resources to proved reserves.
ExxonMobil added 1.7 billion oil-equivalent barrels of proved reserves in 2003 and we've averaged 1.8 billion for the five-year period [1999-2003], for a total of nine billion oil-equivalent barrels of proved reserve additions.
Excluding sales and purchases, we replaced 107% of produced volumes. Over the last five years, proved reserves have been added at an average replacement cost of $4.77 per oil-equivalent barrel.
Additions from extensions and discoveries in 2003 totaled about a billion oil-equivalent barrels and were in such areas as Alaska, Norway, Qatar, Azerbaijan, Kazakhstan and Angola.
We have consistently made net upward revisions to proved reserves in our existing fields. These revisions have averaged over 660 million oil-equivalent barrels each year for the past five years and are a direct result of effective reservoir management and application of new technology in our base assets. The improved recovery category shown includes the Nigeria East Area Additional Oil Recovery Project.
With our industry-leading resource base and proved reserves, our organization is challenged to develop the most attractive of those through a disciplined process of selectivity and efficient deployment of capital. Since the merger, Upstream capex has grown over 50% to just under $12 billion last year.
Spending on projects to develop major new resources accounts for the largest proportion of the growth. When Exxon established a global development company in 1998, a year before the merger, our development company had six projects under way and we were spending about $1 billion a year.
The development company last year spent nearly $6 billion and has 71 projects under way representing a projected total capital spend when all are completed of about $45 billion net. Overall, development costs, calculated on a gross dollars and gross barrels developed basis, to eliminate the effects of fiscal terms, and to represent a matching of full investment dollars with reserves being developed, remain relatively constant at about $3 a barrel.
Exploration spending continues at nominally about $1 billion a year, which is down about 10% from the previous three-year average, with no drop off in discoveries and resource additions. Program capital spending supports our profitable base and represents some 40% of the total E&P capital investment.
Continued exploitation of our huge base business through work programs, facility reconfigurations and applications of new technologies and operating practices are providing the bulk of the earnings and the cash flows to support the large investment in the new developing areas which of course are the source of profitable volumes in the future.
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66 major projects have been brought on line in this five-year period [1999-2003] representing an anticipated net peak production of 1.2 million oil-equivalent barrels per day and delivering about 3.2 billion oil-equivalent barrels of net cumulative production by the end of this decade. We have in effect created the equivalent of another new oil company with these investments.
To put this in perspective, the peak volumes of 1.2 million oil-equivalent barrels a day is roughly the equivalent to three Marathon oil companies. Similarly, the cumulative reserves produced of 3.2 billion oil-equivalent barrels by 2010 is roughly equivalent to the proved reserves of Occidental Petroleum and Burlington combined. And this comparison only includes those projects already started up and producing.
As I'll comment on later, we continue a high level of development activity in other new large resource development opportunities with several additional new startups planned this year. 16 of the 66 projects were started up this past year. These 2003 startups represented over $5 billion in capital expenditures and are anticipated to develop about 1.3 billion oil-equivalent barrels of net resource.
I'll provide a bit more detail on some of the significant 2003 startups.
Our EPS or Early Production System, have now been deployed in three locations, Nigeria, Equatorial Guinea and Angola. The EPS is a generically designed Floating Production and Storage vessel built from a converted crude oil tanker to achieve first production two to four years earlier than using conventional development approaches.
This approach significantly enhances project returns. It provides valuable reservoir performance data on large developments at a point where the final design can still be modified to optimize performance. The first EPS was deployed and started production from the Yoho Field in Nigeria in late 2002.
The Angola and Equatorial Guinea EPS's started up last year and have continued to deliver on the original objectives of the early production system concept: reduced project cycle times, lower cost and high reliability.
Anticipated cumulative volumes to be produced through the EPS ships deployed to-date and the production delivered is on the order of 250 million oil-equivalent barrels net, over 400 million oil-equivalent barrels gross, and includes the redeployment of the Yoho EPS most likely next year to another new resource.
In Equatorial Guinea, the Serpentina EPS [ExxonMobil interest 71%] started up in July 2003, ahead of schedule, and is currently producing over 100,000 barrels per day gross. In Xikomba [ExxonMobil interest 40%], Block 15 Angola, we started up in November 2003, and it is expected to recover 100 million barrels of oil gross.
Current rates at Xikomba are 80,000 barrels per day gross and the vessel has demonstrated a facilities up time of over 95%. As the third EPS to be deployed, Xikomba captured the full synergy benefits of the previous two EPS's with Project Management Team costs reduced by over 40% and execution time reduced by three and a half months.
The Chad project [ExxonMobil interest 40%], as you know, involves the development of a billion barrels of oil gross from three fields in Southern Chad. The full field development consists of 265 wells, a 650 mile pipeline through Chad and Cameroon and a Floating Storage vessel seven miles offshore the town of Kribi, Cameroon.
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The project has had an exemplary safety record with 40 million hours worked without a lost time incident and the Floating Storage unit was completed without a recordable incident of any kind. With the application of our rigorous project management systems and the efforts of our project teams, production from the Miandoum field was brought online one full year ahead of plan. This early oil project is another example of continuing to optimize development projects to maximize returns.
Full field startup was in February of this year, also ahead of plan, and the field is currently producing about 150 thousand barrels per day gross through 127 wells. Those wells have a combined tested capacity of 236 thousand barrels a day gross, so we will gradually be ramping this production up in the weeks ahead.
ExxonMobil also operates over 10 million gross acres in the Doba, Doseo and Lake Chad basins and exploration efforts continued in 2003 with completion of one wild cat and one appraisal well.
Established areas continue to contribute with three projects highlighted here developing 500 million oil-equivalent barrels of resources. In the Norwegian sector of the North Sea, the ExxonMobil operated Ringhorne platform [ExxonMobil interest 100%] started up in February of this past year. The 24-slot production, drilling and quarters platform is tied back to the Balder Floating Production Unit for final processing and export. Ringhorne is currently producing over 50 thousand barrels a day and maximum production is expected to be 90 thousand barrels a day of oil and 35 million cubic feet of natural gas.
Also in the Norwegian sector of the North Sea, the Norsk Hydro operated Grane project [ExxonMobil interest 26%] started up in September. This integrated platform is producing 115 thousand barrels per day gross and is expected to achieve a maximum of 220 thousand barrels a day by yearend. Overall, the North Sea continues to be an important producer for ExxonMobil and we have interest in more than 100 fields in the U.K. and Norwegian sectors.
In North America, the ExxonMobil operated Sable Alma Project [ExxonMobil interest 60%] started up in November with a production capacity of 150 million cubic feet of natural gas per day. Alma is the first of the Tier 2 fields in the Sable Offshore Energy Project located off of the coast of Nova Scotia.
With the advances of sub-sea technology and multi-phase flow lines, new projects often times aren't even visible once installed. These sub-sea tiebacks, which have the wells, manifolds and flow lines all located on the sea floor leverage existing infrastructure that have available capacity or that can be upgraded to accommodate more production capacity. The sub-sea tieback concept permits the cost effective development of smaller resources and insures that the capacity of our surface production facilities remain fully utilized.
One example from the Norwegian sector of the North Sea is the Fram West project [ExxonMobil interest 25%], which started up in October and is currently producing 60 thousand barrels a day gross. And Angola's Jasmim project [ExxonMobil interest 20%], started up in November, and is currently producing 15 thousand barrels a day to the Girassol FPSO. Maximum production from Jasmim is expected to be about 50 thousand barrels a day.
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All of the projects that I've just reviewed have been passed from our Development company to the Production company. Major new development projects that our Development company has underway total 71 projects and they'll develop about 11 billion net oil-equivalent barrels.
About a third of the project investments are in North America with significant investments in other established areas as well.
Three growth areas, Africa, the Middle East, Russia and the Caspian account for almost 60% of the portfolio spending. The ability to effectively execute such a diverse and capital intensive suite of projects is one of the major strengths of the ExxonMobil Upstream organization. This large portfolio of projects are diverse both geographically as well as relative to the types of technologies that are employed.
In 2003, conventional resource developments represented about 80% of our volumes. These same type of conventional volumes remain significant at 60% by the end of the decade.
Volumes from emerging and developing technologies are expected to more than double in contribution by 2010 with substantial growth in deepwater, arctic and LNG. LNG builds on our successes in Indonesia and Qatar with six new trains in Qatar and grassroots projects on the Northwest Shelf of Australia and Angola.
Deep water volumes growth remains strong in West Africa with the Kizomba A, B and C, Bonga, Bosi and Erha. The arctic is dominated by the Mackenzie Delta gas pipelines and the initial phase of development of the Sakhalin I project in Russia.
The challenges presented by harsh conditions and requirements for significant new infrastructure requires the application of leading-edge technologies to deliver the profitable opportunities.
ExxonMobil has a long standing commitment to technology consistently investing at levels above competition, as we indicated earlier.
We're dedicated to developing technologies that will have a significant and lasting impact on the corporation and the industry. An example of this is investment in research development in our approach to LNG. This is not just one technology, but a package of leading edge components that offer a significant competitive advantage across the entire LNG value chain.
We have substantial research efforts designed to ensure ExxonMobil is at the forefront of technologies to manufacture, transport and distribute LNG more cost effectively than any of our competitors. We view these efforts to be important in our pursuit of continued cost reduction.
Our RasGas Train 3, the largest currently operating LNG train in the world, which was built at an EPC unit cost of less than $200 per ton per annum or one-third below that of previous trains.
Increasing individual train sizes to 7.8 million tons per year, which is more than three times larger than the 80s technology, will result in the unit cost at a 16% improvement over this current state of the art RasGas Train 3.
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Our proprietary research in potential designs in membrane storage and modular construction offer significant cost savings for both larger ships and receiving terminals. Future LNG ships will be designed to transport 40 to 70% more LNG than those currently being built and will be 20% more efficient.
Finally, our research efforts are developing terminal designs of the future and we're actively working on offshore designs that will offer cost-effective alternatives to conventional land based terminals.
The deepwater arena provides a clear example of how combining a number of superior technologies, relative to our competitors, enables us to develop challenging resources at lower cost.
ExxonMobil has developed unique proprietary technologies that incorporate an industry-leading understanding of deepwater reservoir geology into the flow simulation models we use for reserve estimates and reservoir management.
EMpower is the industry's only next generation reservoir simulator providing increased accuracy in much less time resulting in optimized development planning, more economic oil and gas recovered and significant business value.
ExxonMobil has also developed several unique hydrodynamic modeling and testing capabilities, part of our long-term commitment to understanding the technical fundamentals and translating this knowledge into reliable designs and lower costs.
And finally, we have long and well-established experience with the entire range of deepwater producing systems, enabling us to select the optimal system for any type of development scenario.
Most arctic operators developed their arctic expertise in the Beaufort Sea Operations of the 1970s and 80s, and then lost their capabilities when that activity declined. ExxonMobil has maintained our arctic expertise through a continuing arctic research program which spans more than 30 years.
ExxonMobil's long history of arctic operations include several milestones that demonstrate the use of technology to achieve innovative solutions in the Canadian Beaufort and in Alaska.
We're applying these technical capabilities to address the multiple challenges at Sakhalin I, in Canada and Alaska. The Sakhalin project will employ a unique combination of technologies, extended reach drilling, arctic offshore platforms, arctic pipelines and arctic marine terminal and tankers for the safe and economic development of this major resource. The benefits provided by our technical leadership translates to a competitive advantage in the Arctic.
Over $3 billion, or 25%, of the Upstream capex last year was spent drilling wells. A sustained focus on drilling and completion is essential because our investments increasingly rely on fewer, very large volume well bores.
In the past, development and production drilling programs typically included contingencies for redrills and provisions for additional wells, should productivity be less than expected.
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Today, however, we're more likely to develop a major resource with six wells versus 60. ExxonMobil has developed and is applying several proprietary drilling and completion technology that clearly lead the industry.
Our broad in-depth research in the fundamental physics of well bore construction and operation has resulted in an unprecedented capability to design to the optimum in advance as opposed to reacting to each well.
We call it the "engineered well bore". The three dimensional surface represents how we use quantitative risk assessment technology to consider the many variables in the drilling process at the same time, along with the uncertainties inherent in each variable to produce an overall probability of success.
Our research has given us the unique ability to understand and simulate the change that occur in a well bore as fluids are produced, and therefore, the ability to identify well specific operating parameters that maximize both the productivity and the longevity of these very expensive wells.
At Chad, some of these new technologies in drilling fluids applied to several hundred wells has produced savings in excess of $25 million. And at Hibernia, we used proprietary technology to design a 30,700 foot measured depth well, which happens to be the longest well ever drilled to a vertical depth greater than 10 thousand feet.
The total savings from this one well at Hibernia were approximately $90 million over the alternative concept. At Sakhalin, our extended reach drilling techniques are allowing horizontal reaches in excess of five miles that will permit drilling of development wells from onshore locations versus more costly offshore structures.
Our frequent involvement with competitors on joint ventures confirms that these technologies are unique and add value that others are not able to capture.
Productivity and reliability are the hallmarks of our drilling technology and this technology is common to all the projects that I've touched upon.
Shifting from technology to geography, ExxonMobil's current portfolio includes a profitable base, as I mentioned earlier, with 1,800 fields producing in 25 countries.
Growth areas represent the areas where significant new resource development projects are underway or planned, which will develop new volumes in the near-term. That includes the Middle East, Russia, the Caspian and Africa.
Together they account for about 20% of our volumes this past year. These same areas are expected to contribute over 40% of volume by the end of the decade.
The established areas characterized by North America, Europe and elements of Latin America and the Far East are still expected to provide in excess of half of our total volumes in 2010. The continued contribution of the established areas is achieved by maintaining profitable work programs and investing in world scale projects in these areas.
With this broad geographic diversity and larger contribution from the growth areas, investment decisions obviously must also be balanced against geopolitical uncertainty, durability of fiscal regimes and the expectations of host governments.
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Managing this geographic diversity and growing importance of emerging new areas is what ExxonMobil's organizational design was built to anticipate.
Our experiences over the past century are brought to bear along with our management systems and our business control systems to ensure we successfully establish these new operations with a long-term future of success. With this perspective, let's examine three of the key growth areas for ExxonMobil's portfolio.
We have a substantial and profitable production base, as well as significant growth potential in West Africa with Upstream activities in Angola, Cameroon, Chad, Equatorial Guinea, Niger, Nigeria and the Republic of Congo.
In the deepwater areas offshore West Africa, ExxonMobil holds interest in 16 blocks totaling nearly 11 million gross acres. Seventeen deepwater exploration wells were completed in 2003, which added almost 500 million barrels to the resource base.
Production last year from West Africa was over 440 thousand barrels a day net and was sourced from Nigeria, Equatorial Guinea, Chad, Angola and Cameroon. This production is expected to more than double by the end of the decade to over 900 thousand barrels a day net.
In Angola, ExxonMobil has interest in five deepwater blocks that cover 4.5 million acres. Through 2003, the company had announced 36 discoveries in Angola with a resource potential of 11.5 billion oil-equivalent barrels gross.
Specifically in Angola Block 15, I mentioned previously, first production was achieved by the EPS deployment in Xikomba. Three additional major developments are being progressed on Block 15, Kizomba A, Kizomba B and Kizomba C. These developments are intended to collectively develop over 2.5 billion barrels of oil at a total investment of around $10 billion gross.
Kizomba A will develop the Hungo and Chocalho fields via a two million barrel FPSO and a Tension Leg Platform. The Tension Leg Platform was successfully installed this past November and the Floating Production and Storage fabrication is complete with the vessel currently en-route from Korea to Angola. The first phase of sub-sea tiebacks is ongoing and the project is on schedule for a late 2004 startup.
Kizomba B utilizes a design similar to Kizomba A to realize reduced cost and cycle time and will develop the Kissanje and Dikanza fields. The Kizomba B Tension Leg Platform hull keel was laid in February 2004 and the project is on track for a 2006 startup.
Activity remains high in Nigeria as well with the first deepwater production start up from the Shell operated Bonga FPSO scheduled to start late this year. Shelf activity also continues with the ExxonMobil operated Yoho full field development, which is on schedule for a 2005 startup to develop 350 million oil-equivalent barrels.
And finally, the ExxonMobil operated Erha project [ExxonMobil interest 56%] in Nigeria is on schedule for an early 2006 startup with an anticipated recovery of about 500 million barrels of oil gross.
2003 production from the Caspian was about 90 thousand barrels per day of oil net and 70 million cubic feet of natural gas net and was sourced from the Azeri-Chirag-Gunashli fields in Azerbaijan and from Tengiz in Kazakhstan.
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Production from these areas is expected to increase to 330 thousand barrels a day of oil net and almost 200 million cubic feet of gas net by 2010 with major new developments and expansions in Sakhalin, Azerbaijan and Kazakhstan. And if you look slightly beyond to the year 2015, we expect net liquid productions from these regions to reach 600 thousand barrels a day.
ExxonMobil operates and holds a 30% interest in the Sakhalin I blocks. More than five billion oil-equivalent barrels are expected to be produced from the multi-phase development in Sakhalin. The initial phase will produce 250 thousand barrels a day [gross] from the Chayvo Field with a startup next year.
Production from the Azeri-Chirag-Gunashli area totaled 130,000 barrels per day gross [ExxonMobil interest 8%] this past year with an estimated recoverable resource of six billion barrels of oil, multiple phases of development are planned. Phase one expansion is 85% complete, and is on track for 2005 start up. And phase two and three are also progressing to develop the east and west portions of the Azeri field, and the Gunashli Field, respectively.
In Kazakhstan, ExxonMobil participates in the Tengizchevroil joint venture, with 25% interest. Tengizchevroil expansions have already increased capacity to nearly 300,000 barrels a day [gross], and increased oil resources to over three billion barrels. Two more major expansions are planned for an additional 440,000 barrels a day [gross] of capacity, and incremental resource capture in excess of three billion barrels [gross]. The first of these major expansions is expected to start up next year.
Also in Kazakhstan, the initial phase development plan and budget for the giant Kashagan field [ExxonMobil interest 16.7%] has been approved by the consortium and the government. This first phase of development is expected to recover over five billion barrels [gross], at a rate of 450,000 barrels a day, with initial startup in 2008. Future development of this world-class resource is anticipated to recover 13 billion barrels [gross] at a peak rate of over a million barrels per day [gross].
Exploration activities continue in each of these regions as well. In Azerbaijan, ExxonMobil participates in three other PSC agreements, covering over 500,000 gross acres in the Azeri section of the Caspian. The first exploration well on the Zafar Mashal prospect commenced drilling in the fourth quarter of last year, with operations continuing.
And in Kazakhstan, two discoveries were made in 2003, Aktote and Kashagan Southwest, in the North Caspian PSC, which includes over a million gross acres.
2003 production in the Middle East was about 450 million cubic feet of gas a day net, and 150,000 barrels a day for net liquids. 2003 gas production was sourced from our [10%] interest in the three existing trains at Qatargas, and our [25%] interest in the two existing trains in RasGas.
2003 oil production was primarily from Abu-Dhabi and Yemen. Gas production is expected to increase to 2.6 billion cubic feet a day by 2010, with an additional six LNG trains on line, and the Al Khaleej gas project. Liquids production is projected to almost double to just under 300,000 barrels a day, as associated condensate and natural gas liquids are captured from the feed streams to the new LNG projects.
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ExxonMobil is continuing to progress significant projects to develop the Qatar North Field. Gross resources to be developed through existing and planned LNG trains and pipeline projects exceeds 22 billion oil-equivalent barrels. A number you'll recognize as roughly equivalent to our current proved reserves. I'll discuss our LNG projects in Qatar more in depth later.
But beyond LNG, the Al Khaleej gas project will further develop the North Field for domestic and regional pipeline sales. Construction is in progress for Phase 1 which is targeted to supply over 700 million cubic feet of gas a day to the domestic industrial customers, with a start up in 2005. Additionally, commercial discoveries and technical studies are continuing to progress on a potential world scale gas-to-liquids project with Qatar.
In other areas of the Middle East, ExxonMobil continues to pursue additional investment opportunities in Abu Dhabi to leverage our technology and project capabilities. We're also pursuing opportunities in Kuwait, including competing for an operating services agreement for the four fields in the Northern part of the country. We continue to remain hopeful that progress in Iraq will one day permit discussions on potential opportunities there as well.
I'd now like to turn my focus to LNG, and first I'd like to start with Qatar, where ExxonMobil is the major foreign participant in the commercialization of the North Field. ExxonMobil participates in several joint ventures with Qatar Petroleum, with our interest ranging from 10% to 30%. This partnership with Qatar Petroleum currently includes six LNG trains, which have a combined capacity of over 20 million tons per year. RasGas Train 3, which started up just this past month in February, will supply the first LNG to India, via the Dahej terminal, and RasGas Train 4, which is currently under construction, will supply LNG to Italy and other parts of the European continent.
Additionally, we have agreements in place to expand this relationship, with further major sales to the U.K. and Continental Europe, and to the U.S. Work is progressing on Qatargas II, which will include the first application of our large train technology, to deliver gas to the U.K. and continental Europe. And in October 2003, we signed a Heads of Agreement with QP to deliver over 15 million tons per year to the U.S., the largest LNG import project on the schedule for the U.S.
Currently planned, plus existing trains are expected to deliver over 60 million tons per year [gross] of LNG by the year 2011.
ExxonMobil is well positioned globally to participate in the growing LNG market. This slide shows the worldwide activities that we are progressing in LNG, with of course a near-term focus on Qatar. We currently participate in LNG sales from both Qatar and Arun, and future opportunities include previously discussed expansions at Qatar, as well as the Northwest Shelf of Australia from the Gorgon and Jansz discoveries, and new opportunities in Angola and Nigeria.
We are actively pursuing terminals to serve markets in the U.S. and Europe. In Europe, we are progressing the Front End Engineering Design on the North Adriatic terminal, offshore Italy, and we're permitting for a U.K. site in Milford Haven. In the U.S., we currently have options on three on shore sites, and are progressing required regulatory approvals.
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Over the next two decades, we anticipate that LNG supplies will grow at an annual rate of 7% per year to meet demand. In 2003, the company participated in LNG joint ventures with a combined capacity of 22 million tons, which is nearly 20% of the global industry capacity. As the largest non-governmental marketer of equity gas in the world, we are uniquely positioned with established marketing personnel and infrastructure in major consuming regions. And we have the technology advantage to be the low cost supplier.
We expect our LNG business to grow faster than the overall industry growth rate, growing our production by a factor of six as the market grows by a factor of four over the next couple of decades.
The capital intensive nature of Upstream opportunities require a disciplined investment program.
The capital program to support the opportunities in the ExxonMobil portfolio is estimated to require about $80 billion over the next eight years. We will continue our strong commitment to exploration, and "by the bit" discoveries, at about a billion dollars a year. The major new developments, many of which I've highlighted for you today, will require about half of this total.
Our profitable base, much of which resides in the established areas, still competes for 40% of the capital as these work programs continue to be some of our most profitable opportunities.
The outcome from our investment program is of course our projected volumes profile. The established areas of the U.S., Canada and Europe remain significant contributors. North America continues to be a significant source of volume, as heavy oil volumes in Canada and Arctic gas replace declines in the maturing lower 48 resource. European volumes decline gradually through the period, largely a liquids phenomena, as gas resources and capacity available for gas sales remain essentially flat throughout this period.
The Far East and Latin America drop largely reflects the continued decline at Arun. Russia and the Caspian liquids growth is driven by the expansions at ACG and Tengiz, and the new developments at Sakhalin and Kashagan. In the Middle East, Qatar is the source of volumes growth from RasGas Trains 3 and 4, and then one additional train every year from 2007.
Steady liquids growth continues in Africa from about 18% of production last year to about 30% of production by the end of the decade.
ExxonMobil's Upstream business is positioned with differentiating competitive advantages. We have the industry's largest and highest quality asset base. Having a large diverse resource base from which to apply our disciplined evaluation, and project planning systems, allows us to select the best opportunities for investment.
Our Upstream functional company organization, which continues to deliver the most profitable business from the base and the new developments, gives us a unique advantage that others see, but they've been unable to replicate. Our business portfolio is underpinned by the corporation's commitment to ongoing research and development, and the integration of our Upstream research company into the business units. And finally our unwavering commitment to business integrity and strict investment discipline remains a key part of our Upstream strategies regardless of current or future prices.
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All of these efforts are supported by the unmatched balance sheet of the corporation to fund all opportunities that meet our investment criteria.
When all is said and done though, the financial results are the yardsticks by which our shareholders should and do measure us. And these are, I believe the primary metrics for the Upstream. Net income per barrel, and return on capital employed. And ExxonMobil remains the leader in 2003, as well as on average for the last five years [Net Income Per Barrel: ExxonMobil $9.45/OEB 2003 and $6.94/OEB 1999-2003 average. ROCE: ExxonMobil Upstream 30% 2003 and 25% 1999-2003 average].
High quality resources, investment discipline, commitment to technology, operational excellence, and the continued progress of our functional Upstream organization have all contributed to these results, and will ensure ExxonMobil maintains its leadership among the world's Upstream companies. Thank you for your attention, it is my pleasure to turn the podium to Ed Galante.
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Ed Galante - Exxon Mobil Corporation - Senior VP
Well thank you Rex, and good morning. Today, I'm going to provide you with an overview of the Downstream and Chemical strategies, operations and results, and also comment on some of our key focus areas for the future.
And I'll begin with the Downstream. It continues to experience significant margin volatility, and following a weak year in 2002, margins improved dramatically in 2003.
Tighter supply demand fundamentals resulting from stronger demand growth in North America, and Asia Pacific, combined with other crude oil and finished product to market factors helped improve earnings to $3.5 billion. Return on capital employed was 13%. In addition to the improved margin environment, earnings were helped by the delivery of operating cost efficiencies and revenue enhancements.
Further initiatives continue to be aggressively executed, leveraging our global scale, proprietary technology, and the benefits of our global functional organization. All helping to offset negative costs and margin pressures. We see these self-help initiatives as critical to growing our long-term results. Through the ups and downs, we continue to maintain strict discipline over our capital investments, and one of the many ways we distinguish ourselves from competition is the manner in which we execute large capital projects.
Now earlier you heard Rex talk about the growth in worldwide oil and gas demand. I'll provide a long-term overview of where we expect the growth for oil products to be, split by sector. Overall, our outlook calls for an average annual growth rate of about 1.6% to 2020, with transportation being the primary driver for growth. The more mature regions of North America, Western Europe are expected to grow at about 1% per year while Japan is forecast to have no growth.
The rest of the world, excluding China, is expected to grow at about 2.5% per year. And I've separated China from the rest of the world because it's one of the few countries with the market fundamentals for new, significant, integrated investments. And our discussions with Sinopec on the potential Fujian and Guangdong ventures remain our primary focus for potential participation in this market, if we can do so on attractive terms and conditions.
But the key message is that growth is expected to be modest in the parts of the world where we, and our competitors have the large majority of our capital employed - the mature established markets of North America, Western Europe, and Japan.
In the Downstream, we make our money from the small difference between two very large numbers. What we pay for the crude that we purchased, and what we get for the product that we make and sell to customers. And the global marketplace controls both of those. The variation between those numbers contributes to the significant margin volatility we see.
As mentioned, margins recovered in 2003 versus 2002 across all three Downstream businesses.
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However, if you look over the longer term, there's an underlying downward trend in real industry margins. This is true in Refining, in Fuels Marketing, and in Lube Basestocks. These declining trends are not surprising, however. Continued productivity gains derived from advances in technology, and operational efficiencies continue to take costs out of running the business.
Also, total refining capacity continues to grow incrementally. Our estimates indicate that this has added, on average, about 1% per year to capacity each year. This is sufficient to meet future refined product demand growth in the mature market that I described earlier. And we see the influence of newer players in increasingly competitive marketplace in both fuels and lubes.
In addition to a modest industry growth and declining long-term margin trend, there are other factors pressuring Downstream returns. Operating costs continue to be impacted by inflation in other pressures. And we see increasing requirements by non-discretionary regulatory investments. While we can and do work to reduce the cost of compliance for innovation, disciplined execution, the fact remains that we expect to recover at best cash cost on these investments. Low sulfur fuels are a good example.
In summary, we can't rely on improved margins or industry growth to improve returns on the Downstream business. However, for ExxonMobil, this environment plays to our strengths. Our strategies are resilient, and our plans are rooted in self-help. Since the merger we've delivered on initiatives that improved returns in this environment, and have differentiated us relative to competition.
Now as we've said earlier, ours is a capital intensive business. And we continue to believe return on capital employed is an important metric for management and shareholders to measure the effectiveness with which we use that capital. Self-help initiatives have had a positive impact on our Downstream return on capital employed, contrasting two years, 1998 and 2003, both in which we had about a 13% return.
The industry factors I described earlier including inflation, forex effects, long-term erosion in margin and a host of others reduced ROCE across the period by more than seven points. For ExxonMobil, these effects have been more than offset by our own self-help of about 8 points.
Now, as you can see, our ability to deliver self-help improvements, distinguish our performance relative to our competitors. And we believe we are well positioned to further increase our performance lead. And I'll give you some more comments on that later in my remarks.
To improve long term ROCE, we have three main levers that we are pulling. We optimize the capital base, the denominator in the ROCE equation, and we increase the margin contribution and reduce the operating costs, two key elements of the numerator.
Our strong technology base and global functional structure provide us with an opportunity to do these things, and to more fully leverage our global business. And we continue to see significant future opportunity. And I'll illustrate with a few examples.
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I'll start with refining and supply. ExxonMobil's refining and supply business is focused on efficiently providing quality fuels, lubes and other high valued products to our customers. We accomplish this through a large, highly integrated and structurally advantaged asset base. In the refining business, scale, and integration are important competitive advantages. Overall, our refineries are 80% larger than the industry average. And over 80% of our refining capacity is integrated with either Chemical or Lubes.
We continue to grow our conversion capacity, cat cracking, hydro cracking and resid conversion, largely accomplished with modest capital investment. These efforts enable us to continually increase the yield of the higher valued products and Chemical feedstocks manufactured in our refineries.
A key benefit of our industry leading scale and integration can be seen in our operating efficiency performance.
This advantage, coupled with our relentless pursuit of cost efficiencies, results in worldwide cash operating costs that are substantially below industry. And our advantage continues to grow.
With energy contributing more than 40% of total refining cash operating costs, improving the energy efficiency of our operations is a key contributor to this performance, with added environmental benefits. ExxonMobil's proprietary, Global Energy Management System, focuses on opportunities that reduce the energy consumed at our refineries.
More than $400 million of potential energy savings have been identified, equal to nearly 20% of the energy consumed at these facilities, and $300 million have already been captured. Beyond this, we continue to make investments in co-generation, where it's economically attractive. More than 90% of the power generating capacity at our refining and chemical sites comes from co-generation. And it meets two thirds of our power requirements at these facilities at lower cost with lower emissions.
And while I've used energy to illustrate the point, we've made progress in all other aspects of costs as well.
Improving profitability also includes identifying and delivering initiatives that increase the available margin. Over the past four years, we've delivered $2 billion before tax in Refining and Supply through our efforts in these areas. Our global functional organization enables us to take best practices and lessons learned from our best refineries and rapidly deploy them around the world. We continue to find ways to improve the process unit availability in our refineries. A particularly important contributor to overall margin improvement in a strong margin environment.
We have proven that large integrated refineries can be operated with very little unplanned downtime. The most recent Soloman survey supports our belief that we do this better than anyone in industry [financial benefit of $225 million/year versus industry]. And beyond margin, better reliability makes us more efficient in both operating costs and capital utilization.
Now one area that you've heard us talk about over the past few years is molecule management. I'd like to take a few minutes to expand on what we believe is a substantial, growing, and sustainable competitive advantage. What we do in molecule management is take industry leading technology in both molecular fingerprinting and process modeling and combine it with real time optimization tools that are designed based on our significant experience in running refineries all around the world.
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A key to squeezing more profit out of a barrel is knowing as much as possible about the crude that is available to the refinery, right down to the molecular level. Throughout our network, we have nearly 200 crudes cataloged, so that we know precisely how the molecules in those crudes will behave under different operating conditions in our facilities.
This enables us to select the slate of crudes for any refinery in our network that will provide the highest margin opportunity, taking into account both raw materials and the fittest product margin environment, as well as the process unit capability at that facility. And once we have the best raw materials in our refineries, our proprietary process optimization models continuously adjust the operating conditions of our process units. This is one of many factors in our efforts to control working capital and inventory. It's helped us take 45 million barrels out of our total system inventory over the past five years.
Overall, we are in the early stages of deriving the financial benefits that we believe will come from full implementation of molecule management technologies. We estimate the potential prize to be more than $500 million, and at best we can tell, no one else in the industry is positioned to replicate this advantage anytime soon, if ever.
Refining is the most capital-intensive part of the Downstream business. Capital discipline is critical to growing long-term returns, particularly in a declining margin environment. Over the past few years, changing product specifications in many markets have required refiners to make non-discretionary capital investments. The most recent example is the introduction of low sulfur fuels [estimated ExxonMobil capital expenditures of ~$3 billion].
ExxonMobil faced this challenge in the same manner that we face many other challenges, we turn to technology. Technology breakthroughs in both catalyst development and process engineering resulted in the development of SCANfining, a technology that enables production of lower sulfur gasoline, often retrofit into existing hardware without the octane loss inherent in the sulfur extraction process.
And it accomplishes that at lower overall operating costs compared with competing technologies. Beyond installation in our own facilities, we continue to extract value from this technology through licensing agreements with refiners all around the world. And between ExxonMobil refineries, and Scanfining licensees, 25% of the low sulfur motor gasoline in North America will be produced using ExxonMobil's proprietary technology.
Turning now to Fuels Marketing. Our Fuels Marketing business is composed of retail, commercial, aviation and marine fuels. And our overall mix is pretty representative of the industry demand. Today I'm going to focus my attention on our retail business, because it represents over half of our total market sales, and the large majority of Fuels Marketing capital employed. Industry growth is modest, and the business remains intensively competitive.
The ability to execute well in any retail business is critical. We believe our global, functional approach gives us an advantage. We successfully leverage our functional organization to achieve substantial efficiencies relative to our competitors.
We take the same approach and apply the same fundamentals to our retail operations that we apply in any other of ExxonMobil's businesses, including setting very high standards, and the relentless pursuit of cost efficiencies and productivity improvements.
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Compare the productivity of our U.S. company operated retail sites, with industry in two areas based on National Association of Convenience Stores data. The first is a measure of on site productivity. The labor hours required to operate the site. We are below industry, and we intend to continue to improve our productivity by increasing the efficiency of our on-site staffing.
The second measure is the average site income contribution compared with industry. On average, we get substantially higher income out of our sites, and we continue to grow this advantage. This in part reflects our ability to grow non-fuels income through the marketing of convenience products and services. Disciplined execution of retail site best practices systematically apply to our service stations around the world, drove down operating costs and increased earnings from convenience products and services.
The improvements in profitability resulting from this approach are best demonstrated through reduction in the sites break even fuels margin. The break even margin is the unit gross margin required from fuels for our average U.S. company operated site to break even, after netting non-fuels income at the site against this total site operating cost. With the combined effect of increased non-fuels income, disciplined management of operating costs and higher average site volumes, we lower this number. It has been reduced by nearly 20% since 2000. And our cost reduction efforts are not focused on the site alone. With our global functional structure, and the enterprise information systems we have in place, we're putting considerable, ongoing effort into capturing above site efficiencies. Leveraging the cost of operating a given retail outlet with the tens of thousands of others we have around the world.
Given the declining trends of retail margins I discussed earlier, and the intensely competitive nature of the retail business, we're finding new ways to boost income at the retail site. And, as in all other aspects of our business, the ability to execute will distinguish the industry leaders from the rest. We have demonstrated our ability to grow earnings from convenience products and services, and we expect that to be a significant contributor to future earnings growth.
C-store retailing is the area that represents the largest opportunity for us. Improved category management and streamlined global C-store operations drive this improvement. Our On the Run C-store chain was recently named 2003 convenience store chain of the year. And we continue to grow sales at a pace above industry.
We also have a portfolio of industry leading programs, including Speed Pass and Upromise. Research shows that the combined effect of these and our other customer loyalty programs can increase ExxonMobil's share of an average U.S. household's monthly motor fuel purchases from about 10% to 90%, very loyal customers indeed.
Given the increasing level of competition in most markets, clearly, one must be very selective and disciplined with retail investment choices, and we are.
One of the early benefits derived from our global functional field marketing organization, was to move to a focus market approach for managing investment. Targeted markets are selected, and prioritized through a rigorous, and disciplined and globally consistent process. Then, within each market, we assess customer preferences, develop detailed marketing models, and produce network investment and operating plans that are executed, employing the strength of ExxonMobil.
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This past year, we conducted a reappraisal of the early focus markets that we approach using this technique. The results are outstanding. The market effectiveness index [the relationship of the percentage of volume ExxonMobil sells in the market to the percentage of the outlets we have in that market] improved by nearly 50%. Our total volumes increased substantially, while the total number of retail sites remain flat.
In addition, the income generated from convenience products and services nearly doubled. And at the same time, we continue to high-grade our worldwide retail network, and we've reduced our total chain by more than 5% this past year alone. The end result is a much more efficient, and effective retail capital base, with further improvement yet to come.
Turning now to Lubes & Specialties. As you know, the total size of this industry is much smaller than either the Fuels or Refining business, and for perspective, it represents less than 1% of the world's oil demand. But on a unit basis, it's the highest valued segment of the Downstream portfolio. We are the world's largest basestock manufacturer. The next biggest competitor is Shell, with less than half of our capacity.
And we have scale advantage. Our average capacity per site is over twice the industry average. We have three strong, global brands, with brand equity in each that we've built up over decades. Our offering is well balanced, with strong positions in all major customer segments and geographies, and our technical capability is second to none. All to say we are well positioned in terms of market presence, facilities, and technical capabilities.
Since the merger, we've taken steps to simplify our global supply chain, and lower the cost to serve our customers. Our capital employed is down 15%, and we expect that trend to continue. We've reduced the number of blending plants from 83 at the time of the merger, to 53 today, with further rationalization to follow.
And as a result, our blend plant utilization is up by 40%. And we've reduced the number of products that we take to market by more than 60%. Our dual brand strategy has enabled us to optimize to a more focused and profitable product line. As with other parts of our business, our focus is on having the most capital efficient lubes business in the industry. We've grown earnings in return by leveraging our existing brand's assets and worldwide presence, and as a result, we haven't had to make high cost acquisitions to be globally competitive.
On the margin front, new product introductions, improved formulations, and changing customer requirements provide the opportunity to continually high-grade our overall marketing offer. We maximize the value of our business under these conditions by developing and deploying segment specific marketing plans around the world.
Our portfolio of complementary brands is comprehensive, and meets our target customers' needs. And we have industry leading technology, and continue to outpace industry in synthetic product sales growth. Our approach is successful in both the mature markets, as well as the high growth emerging markets. For example, in China, we've leveraged our well-recognized brands, key original equipment manufacturer relationships, and technology to achieve a strong, profitable market position.
Over the past three years, sales have grown dramatically, earnings have improved more than ten fold, while capital employed is down.
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Now, for what many appear to be a brief commercial message on a product that truly represents a significant competitive advantage we have in the lubes business. Mobil 1, originally developed over 30 years ago, has a patented molecular structure that provides unparalleled performance.
And we continue to build on this leadership. The latest generation of Mobil 1, Mobil 1 with SuperSyn, provides enhanced anti-wear protection, improved high and low temperature stability, and better overall fuel economy. Mobil 1's position is unparalleled. A recent survey of brands in Fortune Magazine named Mobil 1 the most recognized lubricant brand in the world. And we continue to grow at rates significantly above the industry.
Now let's take a look at how the actions I discussed across the Downstream manifest themselves for ExxonMobil, relative to Shell and BP's Downstream business. First, looking at capital employed. Since 1999, we maintained the amount of capital employed in the Downstream even, allowing for increased non-discretionary investments required to meet changing fuel specifications, and for the impact of forex this past year.
We believe flat to declining capital employed, investing at about depreciation, is prudent in a low growth, declining margin business. In contrast, Shell and BP have both increased their Downstream capital base, largely through new investments and some acquisitions. If you then look at the earnings being generated from this capital base, you see the effect of different strategies.
We're now generating higher income from a flat capital base. The resultant ROCE demonstrates the dramatic change in our competitive position over this time period. These results underscore our belief that success in Downstream requires sustained commitment to the fundamentals of capital discipline and continuous improvement in all aspects of the business. Our people around the world work very hard at this every day, and their efforts have yielded the results I just shared with you.
Now let's turn to Chemical.
Chemical earnings of $1.4 billion in 2003 were the highest of the past five years, and $600 million higher than 2002. This dramatic improvement was the result of self-help initiatives, improved margins, and higher contributions from our new assets targeted at the fast growing Asian markets. Return on capital employed reached 10.2%, up from 6.1% in 2002, our best performance since 1999. Sales of 26.6 million tonnes were equivalent to the record level of 2002.
Our capital expenditures were $700 million. We invested selectively in high return efficiency projects and growth of our less cyclical specialty businesses.
And before I get into specific results and achievements, I'd like to review some of the underlying trends that have a major impact on the petrochemical industry, starting with consumption. Petrochemical demand is expected to grow faster than GDP, as end-use market penetration continues.
Our total worldwide demand projection for three of ExxonMobil's key products, Polyethylene, Polypropylene, and Paraxylene, is expected to increase an average of over 5% per year between 2000 and 2010.
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Looking at demand by geography, it's clear that the growth will not be equally spread around the globe. We expect one-third of the world's growth to occur in China, 55% for all of Asia. Growing in the mature markets is slowing down and about equals GDP growth. The rest of the world will grow relatively fast, but from a relatively small base.
By 2010, we expect Asia will represent more than 40% of the worldwide demand for key commodity grades, and will be equal in size to the mature markets, up from about 17% in 1990. These industry trends are not new, and they were key elements of our strategy when we invested in new capacity in Singapore and the Middle East.
Industry margins for Polyethylene and Paraxylene showed signs of improvement in 2003. The market was very volatile, and overall, sales prices increased between 10% and 40%, more than offsetting higher feedstock and energy costs.
Paraxylene led the pack, supported by stronger demand in Asia. Integrated polyethylene was up, but less dramatically.
Industry margins continued to be low, primarily due to relatively low industry capacity utilization. In the coming years, three key underlying factors will have a major influence on petrochemical commodity margins. The industry restructuring, including the shutdown of uncompetitive steam-cracking capacity, the economy recovery and growth of petrochemical demand, and obviously the pace of new capacity additions. What effect all of this will have on margins remains to be seen.
While the Chemical business will see higher growth than we see in the Downstream petroleum business, and we intend to participate in that growth, our underlying approach to the business is very, very much the same. Self-help is the focus - how you invest your money, how you control your costs, how you use technology are all critical elements of success, and I'll now comment on each.
First, our leading financial performance is closely linked to our unique mix of businesses and our broad geographic manufacturing and marketing presence. All of our 13 businesses are managed globally, and 11 of them are ranked number one or two in their respective markets. Because ExxonMobil is not typically thought of as a chemical company, many do not appreciate that we are the world's largest producer of polyolefins, paraxylene, benzene, butyl rubber and a host of other products.
In 2003, our specialty businesses contributed more than $600 million in earnings. This contribution should increase in the coming years, as we continue to invest in select specialty growth opportunities. Recent investments include the debottleneck of our Baytown butyl rubber plant and the construction of our new metallocene ethylene elastomers plant in Baton Rouge.
The contribution from our cyclical businesses nearly tripled since 2002. Aromatics improved sharply from higher volumes and margins, and our recent investments in Singapore and the Middle East demonstrated significant earnings growth. Our broad geographic presence, illustrated here by our capital employed by region was also a key factor in our overall performance. Our earnings outside the U.S. more than doubled.
The combination of our business mix and geographic breadth will continue to support our earnings growth and our leading financial performance, and it provides us the unique capability to earn solid returns at the bottom of the cycle. And we are well placed for even stronger earnings on the upside.
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Our Chemical business, like all ExxonMobil businesses, seeks and captures efficiencies to maintain its cost leadership. Let me highlight some of our programs and our achievements. Feedstock integration and synergy capture is not new, nor is it ever complete. Building on our experience, we expanded our synergy program between Chemical and refining organizations, with 17 new global initiatives, ranging from supply integration to research and development management systems.
The high U.S. gas price and volatility increased our incentive for feed flexibility in North America. With our flexible crackers, site integration, technical capability and closely integrated optimization processes, we are uniquely positioned to capture this opportunity. The result of our efforts over the years is illustrated by our ethylene net feed advantage averaging 15% versus gas crackers in the U.S., and naphtha crackers elsewhere in the world.
Our manufacturing improvement programs delivered 450,000 tons of reliability gains in 2003. That's the equivalent of one world-scale, grassroots polyethylene plant. In a growth business, that means capital costs avoided and fixed costs saved.
In addition, manufacturing improvement programs and business efficiencies resulted in a workforce reduction of 4% in 2003. Energy efficiencies and savings opportunities are being identified and captured through the extensive use of the Global Energy Management System that I mentioned when I was discussing refining.
In Chemical, energy consumption per unit of output has declined 10% since 2000. 70% of the energy improvements are low-cost activities.
This list covers only some of the Chemical self-help initiatives. These initiatives enable us to continuously improve efficiency and maintain our cost leadership position.
In Chemical, as it is across the corporation, our commitment to technology leadership is another key element of our strategy. It's a major source of differentiation and competitive advantage. We are industry leaders in two major catalyst systems, metallocenes and zeolites.
Our process technology expertise enables us to achieve industry-leading production yields and de-bottleneck our plants at less than 50% of grassroots costs. And working closely with customers, we use our application technology expertise to tailor products to meet their specific needs, differentiating ourselves from competition and providing profitable volume growth.
Our Baton Rouge metallocene elastomers plant, which started up last month, provides an example of how we combine a proprietary catalyst, a proprietary manufacturing process, and our product application knowledge to commercialize a revolutionary new product platform and broaden our product portfolio.
Looking five to 10 years ahead, our long-range R&D focuses on breakthrough technologies offer significant growth opportunities. In 2003, we strengthened our R&D capabilities and created an alliance with Symyx, which focuses on using high throughput experimentation with applications across the corporation to significantly reduce new technology development costs.
Before closing on technology, let me explain that licensing is another source of extra value from our research and development. It generates close to $100 million a year for us in the Chemical business.
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From a growth perspective, we're well positioned globally, including the highest growth areas of Asia. ExxonMobil's manufacturing sites are strategically located to supply the region, and our world-scale facilities are integrated with refining or an upstream resource and thereby benefit from feedstock advantages, a position very difficult for competition to replicate.
In total, we have more than 2.5 million tonnes, or about 30% of our ethylene capacity supporting our growth in the region. This is significantly more than our main competitors. These plants feed a global integrated logistics network, enabling efficient local supply chain optimization and management.
Our products are recognized for their high quality and consistency and are well accepted by a broad customer base in target markets, and our sales growth in China demonstrates our success in the region. 2003 sales were about three times what they were in 2000, and most importantly, they're profitable sales.
Now, as I did with the Downstream, let me close with a comparison of our ROCE to competition. Chemical return on capital employed averaged 12% since 1994. Our main competitors averaged less than 9% over the same period. We've demonstrated our leadership through the business cycle thanks to our unique portfolio of businesses. Our return on capital employed improved significantly in 2003 versus 2002, and versus competition.
Our self-help programs, and our new assets in the Middle East and Asia are delivering results. The petrochemical industry is undergoing significant change. Demand growth has shifted to Asia. Feedstock parities are changing in North America. Major companies are reassessing their strategies and spinning off some of their activities.
Our straightforward, resilient business model is unchanged. We have a disciplined focus on the long-term fundamentals, and an unwavering commitment to the highest levels of performance. These are hallmarks of our success.
Our people around the globe understand these objectives. They are aligned in these efforts, and they continue to deliver results. Thank you for your attention.
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Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Let me take a few moments now to wrap up before we open it up to Q&A. We had another outstanding year at ExxonMobil and the facts really speak for themselves. Consistency, discipline and a rigorous approach to everything we do are the hallmarks of ExxonMobil. Our global functional organization and our relentless focus on operational excellence continued to deliver results to the bottom line. While many of our competitors may seek to copy our approach, it is not something that is easily replicated.
As I think you would acknowledge today, while there are obvious differences across each of our businesses, the approach is remarkably consistent. Every investment decision at ExxonMobil is subject to the same analysis. We will invest to achieve the best long-term return for our shareholders. We do what we say we are going to do and we measure our performance in a consistent and transparent way. We will use our global reach and financial flexibility to grow our business where it makes sense. We will not grow for growth sake, but only when we are convinced that we are building long-term shareholder value.
That concludes our presentation today and I hope, amongst the four of us, we'll be able to respond to any of your questions.
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QUESTION AND ANSWER
Question 1
I was reading in the paper today, one of your competitors says that ExxonMobil is the most conservative in booking reserves.
And I was surprised that you booked Kashagan reserves when the project wasn't officially sanctioned by the government until this year and some of your competitors did not book last year either. Can you talk to us about the criteria that you use in booking reserves?
Lee Raymond - Exxon Mobil Corporation - Chairman & CEO
OK, Rex, why don't you comment on that and specifically on Kashagan. And then I'll come back and make a couple of comments at the end.
Rex Tillerson - Exxon Mobil Corporation - President
OK. The process for booking reserves obviously involves a number of criteria that you have to consider.
As you know, the standard by which the Securities and Exchange Commission holds us as to our bookings is one of "reasonable certainty". There are technical aspects of the presence of the hydrocarbon resources and whether or not we think they can be recovered in an economic fashion. Around that, there's obviously a range of certainty and uncertainty regarding expectations of when things can be done and whether the timing is within the very near term or not.
Our process internally is one of business units evaluating the technical assets of the resources as well as their economic viability against our expectations of costs and future conditions.
They then bring those forward to the management team so that we can then exercise our judgment around whether we think it's prudent to book reserves in light of our certainty that it's progressing. One of the standards that we use is "significant financial commitment" to the development of the resource.
When I say significant financial commitment, that's not to say that's necessarily the final funding decision. Many of these projects are so huge that early on you begin making significant funding commitments to progress the engineering decision, to order long lead time equipment, to pursue comments, to do any number of things.
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At some point, we conclude that we are, in effect, committed to a project in terms of both our financial and technical decision to go forward. At that point we've seen enough in terms of the resource certainty and the economic viability - that it meets our criteria and we have progressed it far enough, largely through some significant expenditures, that we are confident that the resource is going to be developed. Then we can put the reserves on the books.
There is no specific criteria regarding the government formally approving or disapproving a development plan.
Obviously, you must have the rights to the resources and you must have confidence that you can obtain all of the necessary approvals.
The approval of a development plan and budget is not the only approval that we'll have to have for Kashagan to be developed. Just as any other major resource development, there's a whole host of approvals that are required. All kinds of permits that ultimately will have to be obtained.
So our judgment - speaking directly to Kashagan - is that the issues that are outstanding, that would allow us and the consortium to make a decision to go forward, as well as the government's acceptance of the basis upon which we can go forward, - an expectation that we now have a common understanding and a common commitment to move this resource forward and confidence that, in fact, that's now in place and going to happen - that was our basis for taking the proved reserves in 2003.
We had achieved several milestones with the government - from a technical standpoint, the development concept, of which they had already indicated their approval. The timing of their final approval of the DP&B (Development Plan and Budget) was just something that was imminent.
And we could see that it was imminent. We don't wait on that necessarily in every development, again, because it's a function of all of those elements that I just described. Some of the consortium members, as you well know, had previously booked Kashagan, even in years earlier than last year.
Some had decided not to book it and, obviously, they'll book it this year or perhaps they've got some reason to wait to book it even later. But against our criteria and the process that we use, which is no different than what is used for all of our reserve booking decisions, it was clear to us for Kashagan - we were at a sufficient confidence level, both on the technical presence of the resource, the economic viability and all the support that's necessary to see that resource go forward - that we've booked to reserves last year.
Lee Raymond - Exxon Mobil Corporation - Chairman & CEO
I think I'd go back to the point that you were on at the early part of your question, although I don't think you necessarily focused on it. If what I read in the paper is correct, the statement was made that we are the most conservative and rigorous and disciplined in how we deal with the reserves issue.
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That applies to every decision we make on reserves. And that has been a process that has been in place for a long, long time. We make judgments on each one, consistent with that process that has been in place for a long time.
Question 2
Thank you. Your commitment to delivery of superior returns on capital is unparalleled and duly noted.
If ExxonMobil were to come to the conclusion that to have a fully competitive positioning in Russia over the next 10-20 years, you needed to make an acquisition or significant partnership with a local company.
And if you determined over the long-term, the returns on capital are superior in such an investment, would potential short-term return on capital dilution dissuade you - or, perhaps by definition, a short-term return on capital dilution on an acquisition likely to someday turn into better returns long-term. Thank you.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Well, I would go back, I think, to the overarching point that we make - that is, do we think it would be in the shareholders' long-term best interest?
And that does not apply only to Russia - that applies to every investment - so it's not unique to Russia in that sense. And if we concluded that it was in the long-term best interest to the shareholder, we would do it. If it had some positive or - slightly positive or negative effect - in the short-term , then so be it. That's part of making a judgment of whether it's in the long-term best interest to the shareholder.
Question 3
In the last three years, when you've shown the expected production growth chart, there's been a number printed up next to that and discussed in the presentation. That number's been 3%, medium to long-term growth in expected productive capacity.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
On average.
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Question 3 (cont.)
On average. That number is not in this year's presentation. Can you comment on why you've decided not to repeat that number itself?
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Harry, why don't you make a comment about that?
Harry Longwell - Exxon Mobil Corporation - Executive VP
Our outlook, in terms of our expectations of 3% growth in production capacity, over the long-term, really has not changed.
If you just eyeballed the numbers on the curve that Rex showed at the end, in terms of the OEB production over that period of time, it's not too terribly different from that number.
We're basically looking at growth for succeeding years from now in the low single digits on a year-to-year basis. Overall, about 3% is still a good outlook for us.
Obviously, the actual production that comes about is impacted by a lot of different things, as you well know - like demand and production outages and things of that nature. But basically, we're still on track and building the capacity that that we've talked about.
Probably a bit more on the liquid side - Maybe a little bit less on the gas side, in the near term, but overall, we really don't have any changes for our outlook.
Question 4
Can I ask about the timeframe for 2008? My question is whether you think that access rates to reserves for that timeframe - whether those access rates are getting faster, getting slower. Whether you think you can sustain your reserve life, pretty much as it is now, out in that timeframe. And secondly, just looking at the guidance for volumes for a year ago, what your - I think, guidance now for 2008 is actually a bit less than was the case a year ago. I wonder if you could comment on that?
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Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
2008, Rex, versus a year ago?
Rex Tillerson - Exxon Mobil Corporation - President
The question - two questions. One on access to resources between now and 2008 and then the volumes guidance to 2008, which looks to be a little bit less than what we had last year. Is that the question?
Question 4 (cont.)
The access rate question is really for beyond 2008.
Rex Tillerson - Exxon Mobil Corporation - President
Beyond 2008. OK.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Two unrelated questions.
Rex Tillerson - Exxon Mobil Corporation - President
Right. Well, obviously, the access to new resources is vitally important to us because of our size and scale. We must continue to have access to new, large resource opportunities.
That's why you see us active in evaluating and in discussions in the area we've talked about - the major hydrocarbon basins and resources of the world - Russia, the Caspian, the Middle East.
It's much like the situation 15 years ago when we began to evaluate the resource potential of West Africa, which put us in the position we're in today for the volume contribution and resource development opportunities that you saw reviewed today.
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A good deal of our effort today is spent thinking about and working on where is the next West Africa 10 years out, 12 years out.
Because most of what's going to happen between now and 2008-10, is pretty much in place. Those are the resources that we have captured. They're in our 72 billion barrel resource base. We continue to evaluate, to find ways to improve economic viability through technology, through commercial terms or through other mechanisms so that those opportunities can meet our investment threshold as well.
But obviously, we do have an active program underway to obtain access to new large areas. It's a question of time and pace and when some of the host countries in those areas are ready to have significant participation by companies such as our own.
As to the 2008 volumes guidance, I think most of the change from last year is largely related to gas. Some of that is timing of activities in the established areas as well as the new LNG projects, which, of course, come on about in that timeframe, from Qatar. We have the trains that are starting up now, but the large trains that I described, those are beginning to come on-line in about the 2008, 2009 timeframe.
As Harry indicated, and the pie graphs I showed you showed, the growth is consistent with the 3% that we have mentioned.
But year-on-year, it's going to be very uneven because, as you see, these are huge major developments that come on. Particularly LNG or deep water have very rapid ramp-ups to plateau rates within the first year or two.
And then they hold plateau for a while before they begin decline. And so when you start up a major new development, you get a big volume increase, one year to the next. If you then skip a year before the next major crunch of large projects come on, you're going to have some very uneven year-on-year numbers.
But again, when you look over the long-term, and that's what that volumes chart that I showed you really depicts, we'll have this kind of growth (3%) between now and the end of the decade.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
I'm amazed that you can read that chart in 2008 with that kind of accuracy.
Question 5
Thank you. Two questions: First on exploration. Earlier in your presentation you indicated you're going to spend roughly about a billion dollars a year going forward.
If I recall correctly, in the past in your presentations you indicated your long-term target for finding costs is about a dollar per OEBD. Currently, your production is about 1.6 billion barrels a year so - is that possible?
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Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
The finding costs according to the chart Rex had over the last four years has been about $0.70/OEB.
Question 5 (cont.)
Yes, I understand that you are doing very well, but I thought in most of your presentation you're actually saying that longer term you think the average finding costs may be actually back up into about dollar.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
I don't think I said that.
I think you're really missing the point and that our philosophy on exploration is and has been for a long time now that no good opportunity will go unfunded. It is our assessment that under that umbrella, we'll spend about a billion dollars a year and that will result in the kind of reserve adds that we've had and if it turns out there are other opportunities, we'll spend more, but I think you're going at the problem the wrong way and that the objective is to find resources, the objective is to look for quality resources and the objective is to fund the projects that we think are likely to provide those kinds of resources. You seem to think we decide how much money we're going to spend and go the other way and that's not how we run this business.
Question 5 (cont.)
OK, well thank you. Secondly on GTL. Your competitors show and that's such a fan fare when they signed the contract with Qatar, we haven't saw that Exxon's interest - or not interested in that particular market. Wondering if you can comment?
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Actually, there was a comment in one of the presentations today about GTL and Harry, you want to comment about it?
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Harry Longwell - Exxon Mobil Corporation - Executive VP
We're still evaluating GTL very carefully and continue with our discussions with the State of Qatar, you will recall that about two and a half years ago, we signed a Letter of Intent and we're continuing in those discussions.
Question 6
Thank you. Given the strong balance sheet and given the fact that there are also new horizons being opened up in particular places in Middle East such as Libya, is your $10 billion of capital expenditure in Upstream normalized level too conservative especially in view of the fact that you are increasing your short-term Upstream Capex to $12 billion and as a second question, anything you can add on the Libyan situation. Are you interested in getting into Libya initially - I mean discussion. Any update on that? Thank you.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Well actually I think the outlook in terms of the short-term in the Upstream is about $12 billion and it's shown at that level for the next two or three years. The reason it's shown at that level is because we clearly have projects that are identified that are underway that you add it up and see what that the number is. I don't think there's necessarily a constraint on that, but again it depends on the quality of the projects and I wouldn't necessarily conclude that it'll be either higher or lower. It's going to depend on how the projects come along and how we develop them.
In terms of Libya, a lot of people probably don't know the history, but we were the first company to leave so frankly we were the only company that ever got any money from the Libyan government, which is remarkable in its own right. And the reason we left was because we didn't think we could protect our people. The question of going back into Libya is open. I think the explorers think that there may be some opportunities there, but I think I would be fair in saying that I don't have any intent of getting ahead of the U.S. Government.
Question 7
First of all, I'd just like you to run through how you look at emerging market investments? It seems that we constantly hear about the capacity discussed when you talk about production targets and I think it's increasingly important to look at the emerging market areas in terms of the problems associated there with keeping projects up and running due to civil disturbances or delays et cetera?
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So I just wondered how you factor that in when you think about returns from those areas and a second question. I noticed on your charts in terms of production that your decline rate in some of the mature areas did not seem as extreme as the business has witnessed over 2003. I was wondering if you comment on reliability of some of the mature platforms in mature areas and if that's becoming a greater issue for the industry?
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Harry, why don't you comment on that.
Harry Longwell - Exxon Mobil Corporation - Executive VP
Well first in these emerging markets as you described it are kind of new developing areas. In our outlook we basically add the capacity on the schedule that's kind of driven by the project activity and capacity of the wells that we anticipate and then a reasonable expectation from a downtime - kind of a scheduled downtime approach to the business, which we're continuing to reduce really in all of our businesses as we bring best practices to these new areas. But in terms of forecasting on top of that, other outages that we don't have any basis for from an experience standpoint we don't really try to build that into a production outlook and again, this outlook is based on the capacity that we're adding.
But the outages in the developing areas are not that different than mature basins If you look at some of the experiences and problems that we've had in the North Sea from time to time or in Australia or in other places, versus what we're experiencing in Africa. So there's not really a basis from a geography standpoint or a country standpoint to build anything in different in what our experiences have been and the second question was - repeat that again please?
Question 7 (cont.)
Decline rates.
Harry Longwell - Exxon Mobil Corporation - Executive VP
Decline rates right.
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Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Near term decline rates.
Question 7 (cont.)
And the liability issues as well being a function of decline rates. So the uptime of a particular platform as well.
Harry Longwell - Exxon Mobil Corporation - Executive VP
Yes. Well certainly when a lot of our production is basically on a capacity decline, that is if we have downtime we can't turn the volume up the next day and make that up.
There's only a few areas in the world where we have gas capacity that's available to be able to do that as the case might present itself, but the decline rates - I mean there's certainly - that's back to this scheduled and unscheduled downtime comment that I made earlier that applies to our base business and we're trying to handle - to hold that unscheduled - or scheduled downtime to a few percentage points in terms of production capacity which we think probably sets the pace in terms of from a competitive standpoint in the industry and in the total decline, if you were getting to that just looking in our volumes on the projection, it's looking at oil and gas combined and of course that's got new projects added to it and so forth.
The base decline in the business still remains in that 6% range or so that we've talked about in the past.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
I think that another perspective I would put on what Harry eluded to, but I'll be more direct on it and that is when it comes to operations and operational uptimes - look at it the other way positively instead of negatively the way you wanted to look at it - if you look at it positively the facilities that we operate ourselves, we are totally - or we're the operators we have a much better fix on that and performance than in those that are operated by others, which is another continuing issue that we have.
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Question 8
Exxon's industry leading returns have been strongly influenced over the last five years by a very high commodity price environment, your ongoing capital discipline and your ability to achieve large per unit cost reductions substantially from the Mobil merger.
Looking out over the next five years, assuming you're going to keep the same capital discipline, how do you think those two factors, the ability to reduce per unit costs and the commodity price outlook will play out?
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Well that's an interesting question. For some of you that have come to the annual gathering for a long time, that's the same question they use to ask of Exxon before the merger and the amazing thing is that we delivered it every year so I guess I would say to you, stay tuned.
But I think of an industry-leading return, if you look at it over the last 20 years, Exxon and now ExxonMobil have always had the leading returns regardless of what the commodity price environment was and I don't see any reason why that would change - our relative performance vs. the competitors.
Question 9
As I've observed or perceived over the years, I sense a relative degree of risk aversion in the Upstream some of the business relative to both investments in the Downstream area and also relative to the degree of risk aversion that I perceive in your competitors. I'm curious as to whether there's any intent in that regard whether you agree and most importantly, whether this reflects a belief on your part that first mover advantage with respect to a broadly Upstream endeavors is not something that you find to be terribly important.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Well the first comment I'd make I think is that it's not obvious to me how you come to that conclusion. If the point is that we don't run around and try and participate everywhere in everything regardless of the circumstances, if you call that risk averse, I guess I would call it prudent management.
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Question 9 (cont.)
That's not the point. It's time of entry and associated with -
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
No. When you pursue particular opportunity - for example when we entered Angola do you think that was risk averse?
Question 9 (cont.)
No, but later than others. When you went -
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
That's not true in Angola. We were the first guys in the game.
Question 9 (cont.)
How about LNG?
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
How about LNG? Where? We were the first guys in the LNG business.
Question 9 (cont.)
So I guess what you're saying is you don't agree with my perception?
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Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
That's right.
Question 9 (cont.)
Is first mover advantage important to you with respect to Upstream business opportunity?
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Depends on the circumstances. There's no rule that says it is or it isn't. Each one has to be judged on its own merits.
Question 9 (cont.)
OK thanks.
Harry Longwell - Exxon Mobil Corporation - Executive VP
Lee, let me just mention one good example kind of from a first mover standpoint and risk aversion and that's the two deals that we've entered with the State of Qatar over the last couple of years to bring North Field LNG both to Europe and to the United States.
Now each of those deals are in the neighborhood of about $12 billion and they involve new technology in terms of continuing to reduce the costs of the trains, the increase in train sizes, the increase in the ships - of increasing ship capacity by 50% or so and all of those things particularly for the U.S. have to be done to be able to be competitive in a three dollar plus gas market in this country.
So those are really unprecedented. Those will be the largest industrial projects really ever undertaken around gas development so that was clearly first mover to the extent that means anything. I mean that's not one of our criteria obviously, but that was an opportunity and we were able to seize that technology base, cooperation with the State of Qatar and everybody is following in those tracks.
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Question 10
You have a favorable outlook for natural gas going forward evidenced by projected strong activity in LNG. I'm seeing an opportunity set in tight gas that you're showing as in 2010. Could you comment on opportunities in U.S. versus worldwide for tight gas?
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Rex.
Rex Tillerson - Exxon Mobil Corporation - President
We have substantial acreage holdings over tight gas resources and some of you that have been in these meetings the last couple of years have heard us talk about some of our technology developments that we continue to progress to lower the cost of developing tight gas resources and we're talking about ultra tight, not tight gas that historically has been part of the natural gas supply here in the U.S.
Those activities continue to progress with - we have some small developments underway now to test that technology and to continue to get the costs of those developments down so that we are certain that we get the kind of return results that we desire over the long-term in those resources.
There are other tight gas opportunities in Europe, particularly in Germany where some of this technology can and will be utilized as well and those are probably the two major areas that we are evaluating today.
Question 11
Come back to the issue of profitability. You are moving obviously into a period of growth which is something that we haven't seen for a number of years and at the same time the portfolio is shifting towards Angola, Nigeria, Azerbaijan as well.
Can you comment on how you see incremental profitability going forward as some of these new projects come on stream? I wondered if you could contrast that in a few years ago maybe in a lower priced environment when you originally made that investment compared to perhaps a higher priced environment I think most people expect would unfold?
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Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Well I think in terms of the profitability and I guess the way to characterize that would be in unit profitability. You always have the issue of moving out of North America which is effectively what's happening, but once you get kind of past that hurdle - recognizing that North America is a much higher cost area of operations to begin with. So while it may have a more attractive tax structure it has a less attractive operating cost structure. Beyond that, I don't think we see any particular dilution of unit profitability going forward. Is that fair Rex?
Rex Tillerson - Exxon Mobil Corporation - President
Well that's right and when we make these investment decisions obviously they are tested against a range of future conditions so that we're satisfied that the investment will remain robust both in terms of not just a range of pricing, but also a range of costs. Both the cost of the initial investment, and the cost of the ongoing operation, so that, as I said, these things are able to withstand a downside case if that were to come about.
But I think you also then have to recognize the organization emphasis as has been and if the case today towards, you know, an ever relentless pursuit of driving cost down. And that's not really considered where we make that investment decision. We have to take our best estimate of what we think we can operate at today, and then we'll try to improve that. But it is tested against a range so that these are fairly robust under varying conditions.
Question 12
What are the criteria for booking proved reserves as economic viability. What oil and gas price assumptions do you use to book your reserves? And how has that changed over the last four or five years? And finally, would your proved reserves decline if oil and gas prices drop back to the $20 per barrel level for oil, and say the $3.50 to $4 per MBTU level for the U.S. gas.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
I think the answer to that is we use an appropriate price. If you think we're going to tell you the numbers we use, we're not going to tell you. But what we do not do, that's very important, is we do not run that price number up and down as with market volatility.
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Our judgements on reserves are based on a long-term look at what we think the price level will be over some time. We don't want to go through one of these deals that every six months you end up with in essence a mark-to-market which would be crazy for the kind of business that we're in.
In terms of would there be a significant change in reserves if we had a higher price outlook, not particularly, and the converse would be true also.
Question 12 (cont.)
A follow up question, if I might. Many of us are completely confused as to why, or at least perplexed as to why WTI has remained stubbornly in the $30 to $35 per barrel range or higher. Does this, from your point of view, signal a real shift up in the price deck?
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
No. I can remember having a conversation back in about 1995. When somebody said that they have seen a permanent shift in the price and the next year it went to $12 per barrel. So I guess that would be my perspective. I'm always very skeptical of permanent shifts.
Question 13
Thank you. I was just wondering if you could elaborate on your cost cutting goals, which I understand to be $1 billion in 2004. Specifically, what portion of that is merger synergy related, and/or where will the cost cutting occur?
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Well let me get at it another way. And that is we don't set for the organization a so called cost cutting goal. We expect the organization to generate ways to reduce cost. And what they have come in and told us is that for this year, they think that number will be $1 billion. Now we may disagree with that, and say hey, have you looked here and there. But it's not us imposing on the organization.
Secondly, it doesn't have anything to do with the merger. We stopped doing the merger two years ago. You know, at some point you have to get on with life, and the merger is over in that sense.
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In terms of where those reductions will come from, they come from everywhere in the organization. They come from the Upstream. They come from the Downstream. The come from Global Services that support everything that we do all around the world. And to ascribe them to any particular unit of the company isn't particular useful, I don't think, from your standpoint.
Question 14 (inaudible)
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
No we don't do it that way. I mean what we do is we do projects. And we evaluate projects. And we evaluate capital expenditures. And talking about the Upstream, and the volume that comes out is the sum of all of those decisions. It is not, and I've said this many times, I'll say it again. It is not driven by somebody saying we want to grow X%. What we want to do is have projects that are economically attractive to the shareholder. And when we add them all up, it results in XYZ.
If we concluded we didn't have enough projects that fell in that category, we may not have any volume growth at all. But it wouldn't be because we set out zero as our target. It would be because when we looked at the suite of opportunities, and decided which ones met our criteria, this is what we decided to do. We're right now in the Upstream through a period where we have an enormous number of projects, all of which are attractive in their own right. And when you add them all up, the curve, that some people can apparently read with great precision is shown up there.
Question 14 (cont.)
(inaudible), probably at higher ROCE than most of the competition.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
You know, I'll say it - you know, I'm not going to say it - I'm not trying to be flip, but this is not "MBA 101". We make a judgement about what the projects are, the ones we'll support, the ones we think we can execute. Not dilute our execution capability, to give the kind of results that you see.
It's not just a question of calculating a DCF. There's a lot more that goes into the judgement, about which projects we're going to undertake individually and in total than just a DCF calculation.
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Question 14 (cont.)
It seems that the trend in the Downstream, continues to be negative. What leads you to this conclusion, given the fact that the demand is growing? And the environment and the (inaudible)...
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Ed.
Ed Galante - Exxon Mobil Corporation - Senior VP
History is the teacher. I mean we just look and we see this great amount of volatility in the Downstream in all three businesses.
And you look at the trend line that underlies that, and you see a continuous erosion of margins, you know, the numbers behind those trend lines in refining was about 1.5% per year. And as I mentioned, on the refining side of the business, the demand growth from the mature markets is about equal to or slightly below the incremental capacity growth we see in the refining business long term.
In the short term, you'll have little disruptions that will take place, as new regulations come and go and specifications come and go. And product supply in a given geography like the U.S., you know, gets squeezed by those specifications. But the fundamental long-term decisions that we make are driven by that long-term margin. And that is not inconsistent with your intuition.
You know, the productivity improvements, technology advancements, competitive pressure, drive down long-term margins in many businesses. In the refining business or the fuels marketing business or the lube basestock business are not necessarily different than that. So history and intuition both drive us to the conclusion. Our game plan is make business decisions consistent with that long-term trend line. Our strategy is very resilient to that.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
I think the other perspective I would put on that, is that the questioner's intuition is correct. And that also will lead to a lot more volatility.
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Question 15
My question is for Rex and Ed, and I'd appreciate it if they would maybe answer it individually, separately. I'm sure not a day goes by where each of you doesn't think about Lee's pending retirement.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
I know for sure they're not going to answer it.
Question 15 (cont.)
You don't know my question. In all likelihood a year from now, one of you will presumably be standing up where Lee is now.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
You know, you're getting into real trouble.
Question 15 (cont.)
Yes, I know. It had to be asked. I kind of picture the Chairman of this company as the senior steward of the values and the way Exxon has continued to do business and its time tested business model. How do each of you, if you were elected Chairman, think about distinguishing yourself as Chairman, and creating a legacy for yourself with respect to not changing a business model that works.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
I'm going to answer that question. This company and this job is not about legacies. This is not about individuals. This is about a terrific organization all over the world. It has nothing to do with the individuals that are here. We're here for a relatively short period of time. And the objective, as long as I have known, and I have known five Chairman, is to always leave the place better than you found it.
Next question.
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Question 16
Last year, when asked about the outlook for Asian refining, which at that point has been on a long-long period of protracted weakness. I think you were pretty muted about your outlook, you know, pretty much as far as the eye could see. It sounds like - is - was your view about it any different today than it was last year. Is the outlook, maybe things have tightened up better and faster than what you thought a year ago. And does that look brighter?
Ed Galante - Exxon Mobil Corporation - Senior VP
Our long-term view of the situation hasn't changed. Now what we - I think what we've seen in the short term, is that because of some power issues in Japan, demand has been drawn in Japan. We've seen China, demand stronger than we might have seen relative to the long-term trend line, but we haven't seen anything that fundamentally changes our long-term trend line view. We make our long-term investment decisions based on the long-term trend lines that I told you and that I described in my remarks. The day-to-day operations decision we based on the fundamentals of the market today.
The intermediate term, what's going to happen six months from now, nine months from now, a year from now, frankly isn't that significant to the two decisions that I just talked about. It's not significant to your earnings and optimizing your network today. And it's not necessarily significant relative to your long-term, you know, investment profile, unless you see some fundamental change. And as I've indicated we haven't. So we've seen some short-term things happen. How they'll play out over the longer term, time will tell.
Question 17
Where do we stand now and what has to happen to move forward towards accessing Alaska North Slope gas?
Rex Tillerson - Exxon Mobil Corporation - President
Well obviously cost is the big issues. Harry was talking about $12 billion LNG commitments. The Alaska North Slope project would be a commitment of somewhere between $19 and $20 billion, pick a number.
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And today, that's just such a huge investment which would carry with it, obviously a lot of risk that we've got to find some way to try to reduce that cost. Or to deal with the risk, if others want to deal with that.
The work underway today is largely around discussing some of the fiscal elements with the State of Alaska, that might improve the viability of gas from the North Slope.
And then, obviously, we would like to see within the energy bill, the only element that we're really interested in are those parts of the energy bill that deal with streamlining the approvals process here in the United States. Because, again, a project of this size and magnitude when you have those kinds of monies that you're putting out, cannot stand long delays in approval processes, or being held up, you know, over some permit or incremental review that's needed but in the Federal government.
So there is, you know, particular the Energy Bill does deal with that, and that's what we would want to see in place as well, so that we have a certain - a path of certainty on which we know to go in. We know the approval is not certain, but at least we know the pathway is certain and we know what we're dealing with before we start.
So I think it's all of those elements, as well as just continuing to evaluate whether there is not some other way to get the cost down on this very large investment that's necessary. The attractiveness obviously is that the resource is there, it's well known that we are injecting huge volumes of gas for oil recovery on the North Slope so there's - you know, the positive side of it is you don't have a lot of resource risk. The downside is you've got this very huge single step investment to make which is to put a lot of steel buried in the ground in order to deliver the gas.
So I think, you know, our view is that Alaska gas will be put into the marketplace. It's probably slightly beyond the end of this decade, you know, in terms of just all of the things that will have to happen. But if we can find a commercial structure among ourselves and the other producers on the North Slope, that we have confidence in and that is viable, both from a standpoint of the cost, and the risk that would be taken, then obviously we'd be ready to move forward. We just haven't come to that point yet.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
But we also need to realize this is a multi-year process. By the time you get the project defined, get the permits and actually build it, that's several years.
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Question 18
It appears your 10-year F&D cost is in the $4.25 to $4.50 [per barrel] range, which I hope is a timeframe with which you're comfortable. And your three year is probably just a touch higher than $4.50 going into 2003. 2003, if I estimate right, was around $7. One of your larger players is around $6, which is also higher. And the third one I don't have a denominator, so I can't really tell.
But I was curious if you could just talk about what the issues might have been in 2003, or whether we're in a longer - a cycle of higher F&D or whether we're kind of setting up the decks for lower metrics over time. Just interested in your thoughts.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Harry, why don't you comment about this a little bit?
Harry Longwell - Exxon Mobil Corporation - Executive VP
The numbers, I think, the important thing to look at is the averages, you know, over a period of time. And I think the numbers that Rex used in the presentation were over the last three to five years or so. We've been in the $4.50 to $4.75 range or so. That's influenced by a lot of things.
I mean those numbers, really are kind of driven, just taking annual report numbers in terms of proved reserve, bookings, and then capital expenditures. They don't actually go necessarily with the actual dollars and the actual barrels.
The better representation of that, they're also on a chart that Rex shared, which if you just take gross barrels that are associated with the project, and the capital cost for those that over a period of time, we are holding in on development costs at about $3 a barrel. And then add our finding costs, you know, 50 cents to 75 cents range or so. And that has been coming down over time.
Now what actually, you know, ends up getting booked in terms of non-cash cost on the books is more of a function of kind of what are the financial arrangements in those particular areas that you're doing, where there's production sharing agreement. How those costs are handled.
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And what the nets are calculated, and so forth. So more detail than you really care to understand. But as we're looking at these projects and moving forward, you know, we're doing larger projects, which have more resource density and it's helped basically holding costs. The only thing that we can really control and that is the gross development cost pretty constant over a period of time in some pretty tough situations. And that's what our development company and functional organization is delivering to us.
Question 19
Two natural gas questions. One you have a nice piece of hardware there at Arun but the resources are gradually running down. I wonder if there are any possibilities for bringing other gas in there. And has your exploration in the area been impeded by the civil unrest, in Aceh Province?
And secondly, most of the hydrocarbon reserves in the world are natural gas hydrates and are not commercially producible now, is Exxon doing any work on commercializing it.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Harry, why don't you comment on Arun.
Harry Longwell - Exxon Mobil Corporation - Executive VP
Arun is continuing to pretty much be on schedule in terms of the depletion curve that we're looking at there, and it has been long established. And we're just basically meeting expectations. We have some satellite fields that we're bringing on, again, kind of on schedule.
We do have some other blocks there that we're looking at in terms of new development projects, but that's basically not going to change the long-term decline curve that we're on in Arun.
We've done a lot of building there, a lot of exploration over the years. And, you know, I think we understand that resource pretty well. And it's performed as expected.
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Hydrates, Rex.
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Rex Tillerson - Exxon Mobil Corporation - President
We do not have any active research activities underway relative to hydrates other than just monitoring what others may be doing. That, you know, there are obviously a lot of challenges with how you capture a resource like that, and then be able to deliver it, put it into a delivery system, you know, where it can be commercially made available. So at this point, we're not pursuing anything other than just monitoring what others may be doing largely in academic or the government entity today.
Question 20
Thank you. This is a question about the agreement with the World Bank in Chad to divert funds for social programs. I'm wondering what your view of how that's going to work? And will there be more of these things, and more transparency of where else funds go in the social programs?
Lee Raymond - Exxon Mobil Corporation - Chairman and CEO
Yes, I don't mean to quibble with your words, so don't take my comment that way. But this wasn't a diversion project. The whole idea was to allocate the funds. And to be blunt about it, the project, as you heard, is up and running. The money is starting to flow, it's stored into a bank account. To the best of our knowledge no money has been taken out of the bank account. It's under the control of the World Bank. We have urged them continuously now for about two-and-a-half years. I talked to the World Bank all of the time about you better get ready it's coming kind of thing.
And I'm optimistic that the agreements that are in place between the World Bank and the government will be honored. And that being the case, 90% of the money flows to education, infrastructure, water, the fundamentals of what you need in a society like that. And I'm hopeful that will be the case, and therefore, be successful. I don't see another project like that on the horizon. It wouldn't be that we wouldn't be interested in doing a project like that, but fortunately, there are not a lot of countries in the world like Chad. And consequently, to look for an application like that is difficult. But we're hopeful that it will serve as a model for the resource business, not only the oil business, but for a resource business of how you can try and deal with a lot of the issues that have perplexed us for a long period of time.
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